the resilience of electricity infrastructure - evidence - parliament uk
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SCIENCE AND TECHNOLOGY SELECT COMMITTEE
The Resilience of the Electricity System
Oral and Written evidence
Contents
The Alvin Weinberg Foundation – Written evidence (REI0027) ................................................ 5
Aston University – Written evidence (REI0010) ......................................................................... 7
BDO LLP – Written evidence (REI0011) ...................................................................................... 9
BDO LLP, the DEMAND Centre and BEAMA – Oral evidence (QQ 114-123) ............................ 15
BEAMA, BDO LLP and the DEMAND Centre – Oral evidence (QQ 114-123) ............................ 16
David L. Bowen – Written evidence (REI0001) ........................................................................ 17
Stephen Browning – Written evidence (REI0007) ................................................................... 20
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042) .................... 23
City of London Corporation – Written evidence (REI0029) ..................................................... 29
Committee on Climate Change (CCC), Energy Technologies Institute (ETI) and the Resilient Electricity Networks for Great Britain (RESNET) project – Oral evidence (QQ 124-138)......... 35
Confederation of UK Coal Producers (CoalPro) – Written evidence (REI0021) ....................... 57
Rupert Darwall, the Renewable Energy Foundation and Dr Robert Gross, Imperial College London – Oral evidence (QQ 167-175)..................................................................................... 76
The DEMAND Centre, Lancaster University – Written evidence (REI0037) ............................. 77
The DEMAND Centre, BEAMA and BDO LLP – Oral evidence (QQ 114-123) ........................... 83
Durham Energy Institute, Durham University – Written evidence (REI0016) ......................... 97
E.ON UK, EDF Energy and OVO Energy – Oral evidence (QQ 29-43) ..................................... 101
E3C Electricity Task Group (ETG) – Written evidence (REI0033) ........................................... 102
EDF Energy – Written evidence (REI0030) ............................................................................. 105
EDF Energy, OVO Energy and E.ON UK – Oral evidence (QQ 29-43) ..................................... 113
EDF Energy –Supplementary written evidence (REI0053) ..................................................... 114
The Electricity Storage Network – Written evidence (REI0012) ............................................ 116
The Electricity Storage Network, National Grid and Professor Goran Strbac, Imperial College London – Oral evidence (QQ 102-113)................................................................................... 120
Energy Networks Association (ENA) – Written evidence (REI0041) ...................................... 136
Energy Networks Association (ENA) and the National Grid – Oral evidence (QQ 53-68)...... 144
Energy Technologies Institute (ETI) – Written evidence (REI0018) ....................................... 145
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Energy Technologies Institute (ETI), the Resilient Electricity Networks for Great Britain (RESNET) project and the Committee on Climate Change (CCC) – Oral evidence (QQ 124-138) ................................................................................................................................................ 154
Energy UK – Written evidence (REI0034) ............................................................................... 155
The European Network of Transmission System Operators for Electricity and Professor Catherine Mitchell, University of Exeter – Oral evidence (QQ 139-149) ............................... 165
Professor David Fisk and Dr Deeph Chana, Imperial College London – Written evidence (REI0051) ................................................................................................................................ 166
Flexitricity – Written evidence (REI0058) ............................................................................... 169
GDF SUEZ Energy UK-Turkey – Written evidence (REI0036) .................................................. 170
Professor Jon Gibbins, University of Edinburgh, Dr Keith MacLean, University of Exeter and Professor William Nuttall, Open University – Oral evidence (QQ 91-101) ............................ 180
Government – Written evidence (REI0040) ........................................................................... 196
Government: Department of Energy and Climate Change (DECC) – Oral evidence (QQ 17-28) ................................................................................................................................................ 215
Government: Rt Hon Ed Davey MP, Secretary of State for Energy and Climate Change, DECC and Jonathan Mills, Director, Electricity Market Reform, DECC – Oral evidence (QQ 186-198) ................................................................................................................................................ 229
Government: Jonathan Mills, Director, Electricity Market Reform, DECC and Rt Hon Ed Davey MP, Secretary of State for Energy and Climate Change, DECC – Oral evidence (QQ 186-198) ................................................................................................................................................ 249
Professor Richard Green, Imperial College London, Professor Gordon Hughes, University of Edinburgh and Renewable Energy Association – Oral evidence (QQ 80-90) ......................... 250
Professor Richard Green, Imperial College Business School – Supplementary written evidence (REI0050) ................................................................................................................. 251
Professor Richard Green and Dr Iain Staffell, Imperial College Business School – Written evidence (REI0056) ................................................................................................................. 256
Dr Robert Gross, Imperial College London, Rupert Darwall and the Renewable Energy Foundation – Oral evidence (QQ 167-175) ............................................................................ 260
Professor Michael Grubb, University College London and Professor David Newbery, Cambridge University – Written evidence (REI0026) ............................................................ 276
Professor Michael Grubb, University College London, the UK Energy Research Centre (UKERC) and Professor David Newbery, Cambridge University – Oral evidence (QQ 69-79) 277
Professor Dieter Helm CBE, University of Oxford – Oral evidence (QQ 44-52) ..................... 278
Alex Henney, EEE Ltd – Written evidence (REI0015) ............................................................. 291
Alex Henney, EEE Ltd – Supplementary written evidence (REI0055) .................................... 298
Honeywell – Written evidence (REI0019) .............................................................................. 306
Professor Gordon Hughes, University of Edinburgh – Written evidence (REI0049) .............. 314
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Professor Gordon Hughes, University of Edinburgh, Renewable Energy Association and Professor Richard Green, Imperial College London – Oral evidence (QQ 80-90) .................. 320
IESIS – Written evidence (REI0013) ........................................................................................ 321
The Institution of Engineering and Technology (IET) – Written evidence (REI0032) ............ 324
The Institution of Engineering and Technology (IET) and the Royal Academy of Engineering – Oral evidence (QQ 1-16) ......................................................................................................... 342
The Institution of Engineering and Technology (IET) – Supplementary written evidence (REI0052) ................................................................................................................................ 359
KiWi Power – Written evidence (REI0057) ............................................................................. 365
Llinos Lanini – Written evidence (REI0005) ............................................................................ 368
Dr Keith MacLean, University of Exeter, Professor William Nuttall, Open University and Professor Jon Gibbins, University of Edinburgh – Oral evidence (QQ 91-101) ...................... 369
Professor Catherine Mitchell, University of Exeter and the European Network of Transmission System Operators for Electricity – Oral evidence (QQ 139-149) ..................... 370
Moltex Energy LLP – Written evidence (REI0009) ................................................................. 385
National Grid – Written evidence (REI0017) .......................................................................... 397
National Grid and the Energy Networks Association (ENA) – Oral evidence (QQ 53-68)...... 412
National Grid, Professor Goran Strbac, Imperial College London and The Electricity Storage Network – Oral evidence (QQ 102-113) ................................................................................. 429
National Grid – Supplementary written evidence (REI0060) ................................................. 430
Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Written evidence (REI0026) ...................................................................... 432
Professor David Newbery, Cambridge University, Professor Michael Grubb, University College London and the UK Energy Research Centre (UKERC) – Oral evidence (QQ 69-79) . 435
Northern Powergrid – Written evidence (REI0059) ............................................................... 436
Nuclear Industry Association (NIA) – Written evidence (REI0020) ........................................ 437
Professor William Nuttall, Open University, Professor Jon Gibbins, University of Edinburgh and Dr Keith MacLean, University of Exeter – Oral evidence (QQ 91-101) ........................... 440
Ofgem – Written evidence (REI0044) .................................................................................... 441
Ofgem – Oral evidence (QQ 176-185) .................................................................................... 467
Harry Osborn – Written evidence (REI0035).......................................................................... 480
OVO Energy, E.ON UK and EDF Energy – Oral evidence (QQ 29-43) ..................................... 482
PCAH (Parents Concerned about Hinkley) – Written evidence (REI0002) ............................. 498
Marco Pogliano – Written evidence (REI0008) ...................................................................... 500
Renewable Energy Association, Professor Richard Green, Imperial College London and Professor Gordon Hughes, University of Edinburgh – Oral evidence (QQ 80-90) ................. 503
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Renewable Energy Foundation, Dr Robert Gross, Imperial College London and Rupert Darwall – Oral evidence (QQ 167-175) ................................................................................................ 517
Renewable Energy Foundation – Supplementary written evidence (REI0054) ..................... 518
RenewableUK – Written evidence (REI0039) ......................................................................... 527
Resilient Electricity Networks for Great Britain (RESNET) project – Written evidence (REI0025) ................................................................................................................................ 533
Resilient Electricity Networks for Great Britain (RESNET) project, the Committee on Climate Change (CCC) and the Energy Technologies Institute (ETI) – Oral evidence (QQ 124-138) .. 541
Royal Academy of Engineering and the Institution of Engineering and Technology (IET) – Oral evidence (QQ 1-16) ................................................................................................................ 542
Royal Academy of Engineering – Oral evidence (QQ 150-166) ............................................. 543
The Royal Astronomical Society – Written evidence (REI0048) ............................................ 561
RSA Group – Written evidence (REI0028) .............................................................................. 565
The Scientific Alliance – Written evidence (REI0046) ............................................................ 568
Hugh Sharman – Written evidence (REI0006) ....................................................................... 578
Barrie Skelcher – Written evidence (REI0003) ....................................................................... 598
Dr Iain Staffell and Professor Richard Green, Imperial College Business School – Written evidence (REI0056) ................................................................................................................. 603
Storelectric Ltd – Written evidence (REI0004) ....................................................................... 604
Professor Goran Strbac, Imperial College London, The Electricity Storage Network and National Grid – Oral evidence (QQ 102-113) ......................................................................... 610
UK Energy Research Centre (UKERC) – Written evidence (REI0031) ..................................... 611
UK Energy Research Centre (UKERC), Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Oral evidence (QQ 69-79) .............. 631
UK Hydrogen and Fuel Cell Association – Written evidence (REI0023) ................................. 645
The Utility Regulator – Written evidence (REI0024) .............................................................. 649
The Alvin Weinberg Foundation – Written evidence (REI0027)
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The Alvin Weinberg Foundation – Written evidence (REI0027) 1. The Alvin Weinberg Foundation is a charity which promotes next generation nuclear energy to combat climate change and achieve long-term energy security. We are particularly interested in the Molten Salt Reactor (MSR), one of the six Generation IV nuclear concepts1. 2. MSRs represent a revolutionary advance in nuclear fission technology. The only nuclear reactor to use liquid fuel, the MSR is extremely fuel efficient, generates very little waste, and offers unique passive safety features. Crucially, the MSR has outstanding load-following capability and will provide a low-carbon alternative to gas as a flexible source of electricity to support renewables. 3. MSRs burn up between 90% and 98% of the energy contained within uranium or thorium fuel. In solid-fuelled reactors, fission products accumulate which reduce the lifetime of the fuel rods, allowing only around 3% of the energy contained within the fuel to be exploited. MSRs continuously remove fission products so that the fuel can be almost fully consumed, leaving only small quantities of waste. Passive Safety 4. MSRs offer a range of inherent safety features. They operate at atmospheric pressure, eliminating the possibility of a pressure explosion. MSR temperature regulation is passive, so no control rods or active cooling system are required. The heat generated by fission expands the molten salt, decreasing the level of reactivity, which leads to a contraction of the molten salt and an increase in reactivity, and thus a self-regulating system. Load-Following Capabilities 5. MSRs can load-follow reliably and flexibly, making them a superb candidate to replace fossil fuel back-up generation currently required as support for intermittent renewables. The passive temperature system enables MSRs to load-follow automatically. As more heat is extracted from the reactor, the salt temperature goes down, causing power output to increase, thus responding instantaneously to demand. 6. In addition, MSRs have far greater load-following capability than solid-fuelled reactors due to their capacity for online removal of xenon gas2. Xenon is a neutron-poison which increases in quantity in solid-fuelled reactors when the power level is lowered, thus limiting load-following operation. In MSRs, xenon is constantly bubbled out of the reactor via the off-gas system which enables MSRs to be among the most flexible load-following nuclear reactors. 7. The capital cost of MSRs promises to be significantly lower than for current generation nuclear plants, in large part due to the intrinsic safety features, which eliminate the need for expensive safety mechanisms and shielding. UK-based start-up Moltex Energy are
1 Generation IV International Forum website, ‘Generation IV Systems’. 2 Transatomic Power, ‘Technical White Paper’, March 2014, p. 24.
The Alvin Weinberg Foundation – Written evidence (REI0027)
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developing an MSR design with the assistance of researchers at Manchester and Edinburgh University. Moltex believe that their MSR could compete with gas as a load following technology due to its relatively low construction and operating costs3. Research and Development 8. China leads the world in MSR development with its $70 million a year thorium-fuelled MSR program. The Chinese Academy of Sciences is working on two MSR iterations, the first solid-fuelled and molten salt-cooled, the second both fuelled and cooled by molten salt. A recent report suggests that China is aiming to commercialise the technology by 20244. 9. The UK is home to number of world experts in the use of molten salts for nuclear applications. The National Nuclear Laboratory, University College London, and the universities of Manchester, Nottingham, Edinburgh and Cambridge have formed the REFINE research consortium, which is focussing on the use of molten salt for spent fuel reprocessing. REFINE is training up a new cohort of molten salts scientists, whose expertise could be directly applied to MSR R&D work. 10. Sadly, at present, there is no UK MSR R&D programme for these scientists to work on. The Nuclear Innovation and Research Advisory Board (NIRAB) is due to make recommendations to government in January 2015 regarding the UK’s Generation IV reactor R&D capabilities. We are hopeful that NIRAB will recognise the important role that MSRs could play in the UK energy mix by recommending the establishment of a national-level MSR R&D programme. The UK could make a major contribution to MSR technology development with an investment of around £5-10 million per year. 19 September 2014
3 Moltex Energy LLP, ‘The Simple Molten Salt Reactor: Practical, Safe and Cheap’, Conference Presentation, Institute of Chemical Engineers, Sustainable Nuclear Energy Conference, 11th April 2014. 4 ‘Chinese scientists urged to develop new thorium nuclear reactors by 2024’, South China Morning Post, 18th March 2014.
Aston University – Written evidence (REI0010)
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Aston University – Written evidence (REI0010) 1. As noted in paragraph 2 of this call for evidence “Energy policy in the UK focuses on balancing three interconnected demands: energy security, affordability and decarbonisation” and this call for evidence “looks specifically at the current and future contribution of science and technology to ensuring the resilience of the UKs electricity infrastructure.” 2. In order to ensure that the necessary decisions about “large scale investment in new electricity infrastructure (which) will be needed over the coming decades” are made appropriately, it is necessary that these decisions are evidence based, informed by the consensus of scientific opinion, and underpinned by the ethos embodied within the Haldane principle. 3. The UK has a vibrant and effective research base investigating issues relating to the resilience of the electricity infrastructure, and potentially, a vast corpus of data is already in the public domain, and will continue to be made available over the short and medium term timescales considered in this review. It is essential that all this data is made available and considered holistically and appropriately in order to inform these ongoing considerations. 4. One concern of note with current electricity infrastructure research relates to the difficulties associated with trialling new technologies on a network due to the conflict with customer minute losses and customer interruption reporting. This means that much research to date is small scale, risk adverse and contains significant modelling based on assumptions which may be wildly wrong. Trialling new, game changing technology is unlikely to occur to any great extent within the UK under these current constraints. 5. In addition, there is a potential trade-off between cost and resilience - focussing on cost reduction doesn’t necessarily lend itself to increasing network resilience as design margins are pushed towards their limits; however, mode adventurous and innovative solutions may not be as favourable as the cheaper alternatives. 6. It should also be noted that the HVDC (high voltage, direct current) technology for connecting between countries is changing rapidly and voltage source multi-level converters are proving to be popular on new builds. The reliability and long term running experience of these items of equipment are not so well established and thus their reliability and subsequent impact on resilience can be determined. 7. In terms of research funding (the aspect of this review we feel best placed to comment on as a research-led institution), in the short term, the current policy (delivered on behalf of the Government by the Engineering and Physical Sciences Research Council, EPSRC) of investing in this area primarily through recognised centres of excellence is well founded, and has already shown tangible impacts; however, the current system also provides mechanisms for researchers outside these established centres to investigate excellent ideas of huge potential benefit. This is essential to the continuing support of excellence that will underpin the development of future technologies in this arena. This mechanism is highly effective, and the
Aston University – Written evidence (REI0010)
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potential exists for other governmental agencies to avail themselves of EPSRC resources and expertise to ensure that their investments are also underpinned by the standards of excellence that are embedded in EPSRC processes. The continuing close collaboration between the EPSRC and Innovate UK (formerly the Technology Strategy Board) provides an effective potential route to market for these technologies. 8. The next six years will provide insights which will help inform future decisions – ongoing projects include – searching the national database, gateway to research (http://gtr.rcuk.ac.uk/), reveals 956 active research projects using the search term electricity infrastructure resilience, with a total of 2232 projects on the database. It is in the nature of research that insights tend to occur towards the end of the individual project, or even following a period of reflection after the end of the award. 9. It is unlikely that a market led approach will be sufficient to deliver resilience without ongoing integration with the research base. 15 September 2014
BDO LLP – Written evidence (REI0011)
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BDO LLP – Written evidence (REI0011) Author: Michael Ware, Partner for New Energy and Environment Short term (to 2020) 1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden
shocks? How well developed is the underpinning evidence base? 1.1. No comment
2. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the light on’? 2.1. As the Committee will be aware, electricity demand in the UK varies hugely during the course of the day with the greatest peaks usually between 4pm and 7pm on winter evenings. We believe that demand-side response could play a much larger role in reducing these peaks, both by calling on unused generating capacity and by incentivising end users to reduce demand at these times. By developing policies that minimise the impact of these peaks, the Government can partially reduce the need for expensive new capacity. Many organisations, e.g. hospitals, have on-site generation particularly for emergency use, which could be flexed to help meet peaks in demand.
2.2. We acknowledge that the National Grid have already implemented polices in this area either directly or through aggregators to schemes such as National Grid’s Short Term Operating Reserve (STOR) providing up to 2.8 GW of flexible capacity. As the Committee may be aware, aggregators use smart grid technology to communicate directly with electricity generating and consuming equipment on remote customer sites via secure connections. This gives the grid the ability to increase generation and/or reduce consumption during peak times from sites that individually would be too small to meet National Grid’s 3 MW minimum to contribute to STOR, e.g. supermarkets remotely turning off freezers briefly at peak times. Public sector buildings may also play a significant role here, with aggregation of flexible demand across estates delivering both cost savings and extra grid resilience. 2.3. We feel that demand management during peak periods has significant potential and should be the subject of more significant investment and tax allowances. There may be an argument to rebalance an element of Government investment away from creating new renewable capacity and towards demand management technology.
3. How are the costs and benefits of investing in electricity resilience assessed and how
are decisions made? 3.1. As the Committee may be aware, global investment in renewables in 2013 was $214 billion and the majority of this was in China, the US and Western Europe. This is a truly international market with free movement of capital across borders. Although the
BDO LLP – Written evidence (REI0011)
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investment community is largely centred in London, there is no sentiment towards the UK and projects in this country have to compete with wind, solar and waste to energy plants elsewhere in the world. In this context, investment decisions tend to be made on the basis of:
reliable and secure sources of energy
unleveraged project internal rates of return (IRRs need to be 12%-15%)
long-term certainty of tariff support
stable currencies
ability to repatriate dividends and capital across borders
sympathetic planning regimes and ease of grid access and connection.
3.2. Unfortunately the Government in the UK tends not to appreciate that it is in competition for capital with other countries and hence ignores the fundamentally risk averse nature of project financiers on a depressingly regular basis. Tariff regimes are almost constantly under review, there is no strategic cohesion between Central Government, the local planning regimes and the National Grid, and recently the Scottish referendum has unsettled long-term currency trading. We recognise that a lot of these issues are macro political and not easily resolved but to our mind there are some easy low-risk wins such as:
A five to ten year moratorium on changes to tariff structures, capital allowances and legislation applying to Venture Capital Trust/Enterprise Initiative Scheme as it applies to renewables. This would unlock a secure source of capital.
Greater coordination between DECC, the National Grid and planning policy.
Developing greater experience within DECC of the reality of project finance, including secondments to banks and developers.
4. What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? 4.1. Our comments here cover two policy areas: the Government’s new Contracts for Difference (CFD) policy and the role of the Green Investment Bank (GIB). Contracts for Difference 4.2. We welcome the move to the Contracts for Difference subsidy scheme and feel that the auction-based element for the process will secure better value for money for the taxpayer. However, we have four concerns regarding the process. I. Our understanding of the system is that bidders submit a Strike Price bid per MWhr
for their project. These are then aggregated until the annual budget cap is reached. However, at that point all the successful bidders receive the Clearing Price which will have been set by the highest Strike Price bid accepted in that delivery year. This price will inevitably be higher than all but one of the preceding bids submitted because the highest price bid before the cap is reached determines the price for all
BDO LLP – Written evidence (REI0011)
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earlier bids. So in essence the Government is proposing to create a system whereby the bidders having established and bid a profitable Strike Price per MWhr for their project are then paid a potentially much higher Clearing Price per MWhr without any need to provide project-specific justification or rationale. To our mind this is an absurd quirk of the system and we are aware that our concerns are shared by project developers who feel that the budget will be spent on too few projects at artificially high Clearing Prices. We feel that a process should be adopted so that each successful bidder receives the Strike Price per MWhr they bid irrespective of what other bidders submitted.
II. We note that the CFD Administrative Strike Price is not adjusted for regional differences in costs and the availability of renewable energy sources such as wind, solar etc. The Government is missing an opportunity to make the CFD budget an engine for regional growth by either conducting area-specific auctions with an allocated budget or setting higher Administrative Strike Prices in areas of low economic growth.
III. We note that bidders in the CFD process have to have received full planning consent and more importantly grid connection offers for the projects before they can participate in the process. We feel that this will reduce the number of bidders and significantly disadvantage smaller single-project companies and Community Interest groups. The availability of planning consents and grid connection varies hugely by region and is a significant factor delaying the development of renewables infrastructure in the UK. We feel that if developers have to spend money on obtaining these consents before they have the certainty of a CFD contract they will be more likely to focus on the less risky technologies and regions, and act as a brake on smaller developers vs large established companies. Our view is that the Government should require planning and grid offers within a specified period, i.e. twelve months subsequent to the auction not before.
IV. Finally, we note that there are no refinancing clauses in the standard CFD contract. As you may recall this was a trenchant and widely publicised criticism of the Private Finance Initiative (PFI) scheme, and we feel the same arguments apply here. Projects inevitably become less risky once operational and this is reflected in a diminution in the cost of finance. We feel that the CFD contract should have provisions to recover some of the benefit of a refinancing event for the Government through a reduction in the Strike Price, i.e. where there is overcompensation for projects compared to their initial financing points there should be a built-in mechanism to allow a proportion of savings to flow back to the overall scheme, enabling greater deployment.
The Role of the Green Investment bank in the transition to low carbon generation 4.3. We also feel the role assigned to the Green Investment Bank should be reviewed and amended. As noted above, total investment in renewables in 2013 was $214 billion so there is no global shortage of liquidity and we do not see the need for State-sponsored banks in the UK to focus on lower-risk larger-scale renewable infrastructure.
BDO LLP – Written evidence (REI0011)
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Indeed, we have recently encountered situations where the presence of GIB as senior debt provider has actually discouraged other banks from participating in deals and to our mind this is evidence that this is not the correct role for the bank. 4.4. There is however, with the retrenchment of the Cooperative Bank, a shortage of UK banks who are prepared to lend to projects at the sub £20m scale, where a lot of the more emerging technologies such as anaerobic digestion, small-scale wind and solar are to be found. This funding gap is currently being filled by Venture Capital Trusts and dedicated Infrastructure funds who are lending money at 12%-15% compared to the 6%-7% available from banks as debt for larger projects. This is unnecessarily expensive funding given the risk level of these technologies and is a net cost to the taxpayer. 4.5. The traditional objection by the banks to sub £20m lending is that the transaction costs are uneconomic. However, we feel that for a state-backed institution such as GIB, the role of the Treasury in PFI is instructive in this regard. As you may recall the Treasury worked with the banks to produce a standard suite of contracting documents for PFI deals so as to minimise the transaction cost of negotiating 800 plus projects and ensure consistent access to liquidity. We feel that GIB could undertake a similar role on renewable energy projects, i.e. produce a standard suite of project finance documents for sub £20m deals and act as a lender to these projects.
Medium Term (to 2030) 5. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will
new risks to resilience emerge? How will factors such and intermittency and localised generation of electricity affect resilience? 5.1. No comment
6. What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? 6.1. No comment
7. What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? 7.1. See our comments above re CFD and the GIB.
8. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have are evolutionary impact on electricity infrastructure and its resilience?
BDO LLP – Written evidence (REI0011)
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8.1. We think that advanced waste to energy technologies have huge potential to become more mainstream in the UK. We note that the UK lags significantly behind the rest of Europe in recovering energy from waste. Sweden and Denmark for example recover energy from 50% of the municipal waste stream and the Netherlands 35%, whereas for the UK the figure is approximately 12% and 40% is sent to landfill. 8.2. The Government’s 2011 waste review suggested that renewable electricity generation from waste could treble to 2.6 TWh by 2020. We also note that 2.4 million tons of Refuse Derived fuel (RDF) is currently being exported and such is the level of supply compared to demand that European end users receiving the RDF (cement kilns and waste to energy plants) are being paid circa £60 to £80 per tonne by UK suppliers to burn what is in essence fuel. 8.3. This market has grown rapidly in the last few years and as a result, UK taxpayers are indirectly subsiding European cement and electricity markets. To our mind this is an absurd situation caused by local planning objections to incinerators and a lack of Government support for the technology.
9. Is UK industry in a position to lead in any, or all, technology areas driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system? 9.1. We don’t feel that that the State has a significant role to play in promoting particular technologies. We note with concern that the CFD process still has two tiers and technologies that are perceived to be more risky such as wave, tidal and advanced waste to energy are to be awarded a higher CFD than more established technologies such as solar and wind. To our mind this is a hangover from the ROC regime whereby the Department of Energy and Climate Change tried to manipulate technology development by awarding higher ROCs to less developed technologies in order to act as a carrot and pull through projects. 9.2. However, the cost of a project is subject to many competing variables such as the cost of technology, the grid connection, the energy source, the cost of funding and many more. We feel that it is beyond the expertise of civil servants to second guess the impact of all of these factors acting simultaneously and in trying to manipulate subsidy/tariff regimes to push or pull the development of particular technologies. The Government is always either paying too much, i.e. the early days of solar when tariff prices fell more quickly than the subsidy, or too little, i.e. the very high levels of subsidy being awarded to wave and tidal are still deemed insufficient. 9.3. In our view, the Government will never get this judgement right and the legitimate role of the State in this process should be to procure renewable energy capacity irrespective of the technology. Governments are very bad at trying to pick winners and the market is a better arbiter of which technologies should be promoted.
10. Are effective measures in place to enable Government and industry to learn from the
BDO LLP – Written evidence (REI0011)
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outputs of current research and development and demonstration projects? 10.1. In our experience there are very few mechanisms for Government to learn from current developments in renewable technology. There is a lot of activity taking place in areas such as waste to energy and energy storage but this tends to be under the radar of DECC. Similarly grant funding regimes are opaque and dispersed across central and local Government. We see an opportunity for a national body for promoting research and development into renewable energy with all current grant and funding regimes aggregated into a single mechanism.
11. Is the current regulatory and policy context in the UK enabling? Will a market led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? 11.1. We feel that the Government could play a stronger role in directing the scale at which renewable energy is produced. We note that in Germany 46% of all renewable capacity is installed as micro generators on either houses or farms. This dispersed approach has the obvious advantages of:
being quicker to procure,
is on a project by project basis far less capital intensive, and
avoids the issues of planning and grid connectivity that stifle the development of larger projects.
11.2. We feel that the Government could do a lot more to encourage dispersed capacity by amending the personal taxation system so that investment by taxpayers in domestic renewable energy or energy efficiency measures qualified for the same tax breaks as investing in VCT or EIS schemes. At the moment we have the situation where the individual receives a tax break for investing in a VCT and receives a return on his investment of say 5%- 7% and the VCT then invests in renewable energy at a higher cost of capital (i.e. 12%). To our mind there is obvious potential to reduce the cost of installing capacity by taking out the VCT and transferring the tax break to the domestic installer. This could be used instead of a tariff regime for domestic installers.
16 September 2014
BDO LLP, the DEMAND Centre and BEAMA – Oral evidence (QQ 114-123)
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BDO LLP, the DEMAND Centre and BEAMA – Oral evidence (QQ 114-123) Transcript to be found under the DEMAND Centre
BEAMA, BDO LLP and the DEMAND Centre – Oral evidence (QQ 114-123)
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BEAMA, BDO LLP and the DEMAND Centre – Oral evidence (QQ 114-123) Transcript to be found under the DEMAND Centre
David L. Bowen – Written evidence (REI0001)
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David L. Bowen – Written evidence (REI0001) 1a : Between the Wars, and just in time for the outbreak of the second World War, a 132kv. National Grid network was constructed to link up the regional Power Generators. They were a mixture of private and Council run units. This allowed for energy to be moved to manufacturing facilities vital to the War effort. 1b ; After the second World War, generating plant was worn out. It was clear that a unified generating body was the natural progression from the National Grid. New plant was needed urgently, but the many plant owners could not afford the huge costs involved. With help from the Americans, in the form of Marshal Aid, the Government of the day, Nationalised the entire system. 1c ; Efficient, large, generating stations, to replace the many, best suited the National Grid. 1d ; A unified system operating under the control of the National Grid, rather like a single heart beating to the instruction of a brain, was the result. First called the BEA, the British Electricity Authority, then the CEA, the Central Electricity Authority, and finally the CEGB, the Central Electricity Generating Board. The National Grid grew into the Super Grid at 400kv. This was designed to cater for the doubling of demand every 10 years, up until the 1970’s, when deindustrialisation stopped this growth. 1e ; Electricity distribution Boards were set up. The cost of electricity to these Boards, was determined nationally by the Generators, on a regular and continuous basis, and called the “Bulk Tariff”. Every generating station had to monitor its efficiency on a weekly basis. Every month they had to produce a STEP ( station thermal efficiency and performance ) factor. National Grid Control used this to determine the plant that would be called upon to run. It was “cheapest first, and dearest last”. As cheaper, more efficient, plant came into service, the older plant was less frequently called for. However, it was deemed prudent to maintain availability, and to maintain 30% surplus over peak demand. Older plant was decommissioned when this could be maintained without them. 1f ; This evolved system was considered to be the best in the World. It produced the cheapest electricity in Europe, with the exception of Norway, and from the dearest fuel. 2a ; The dissolution of our coal industry, and our dash for cheap gas, caught our energy manufacturing industries unprepared, with no time to readjust. Their designs were for large steam generating plant specified by the CEGB. Gas plant was already being made in Europe. Transfer of orders to the Continent led to the demise of our industries. 2b; Privatisation of the electricity industry has reverted to its fragmentation, exacerbated when foreign investors took control of most of the industry.
David L. Bowen – Written evidence (REI0001)
18
2c; Electricity is now traded as a commodity, with traders facing each other fighting for a share, and maximum price. 2d; National Grid Company still has the roll of controlling the generators. They have to forecast each day, in advance, the demand curve. This is when they have to negotiate with traders for the required generation, and for the price they will have to pay. 2e; Wind and solar power is out of their control, other than to “constrain them off” to maintain stability. Wear and tear to main generating plant is a concern, due to their sporadic activity. 2f; Instead of one heart and brain, we now have multiple hearts, with some outside of the body, dependent on external, intermittent, stimuli. 2g; To break up the electricity supply industry by further fragmentation, will not encourage competition. Especially when a “middle man” retailer is considered to be a supplier. 2h; We need to return to a unified system where a “clearing house” can determine the generated price of electricity, Bulk Tariff. Generators should be freed from having their own customers. Costs of individual generating stations must be provided to the National Grid, so that they can run plant on merit. This would eliminate Traders. 3a; Our closure of coal fired Power Stations, imposed on us by the EU, for environmental reasons, has left us very vulnerable. We have little headroom above maximum demand. 5% at best. 3b; What can we do about this? 3c; Stop further closures. 3d; Mothballed gas plant must be made fully available, without having to pay owners to do so. It is their responsibility as we are paying for them in our bills. 3e; We should discourage further development of wind and solar energy. The cost to benefit is hopelessly high, and impractical. 3f; Nuclear is also hopelessly expensive, as envisaged, having to import the technology from overseas. The French are 70% nuclear, and charge their customers £46 a MWhr. They have persuaded us to pay some £95 a MWhr., and to maintain the differential for 35 years if they build one for us, so called the“strike price”. The crippling cost of disposing of our, already enormous, stockpile of Plutonium, should be a disincentive. 3g; If we are able to manufacture our own “small” reactors, based on those used for marine propulsion, we should be able to avoid this crippling “strike price” arrangement, if Nuclear is the way we want to go.
David L. Bowen – Written evidence (REI0001)
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4a; What coal mines we have left we must exploit to the full. In situe gasification of coal seams now appears to be a viable option and must be encouraged, as indeed must be Fracking. We must, however, begin to do things for ourselves again, or else all profitable returns are destined to continue to go overseas. 22 July 2014
Stephen Browning – Written evidence (REI0007)
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Stephen Browning – Written evidence (REI0007) Author: Stephen Browning BSc(Hons) MIET MIEEE MEI, Electricity Efficiency - APL 3454, www.eleceffic.com I hope the text which follows will help; it is taken from various sources and I haven't had a chance to clean it up. My background, observations on strategy and papers on Future Power Systems can be seen at www.eleceffic.com "Everything affects Everything Else simultaneously in Electricity Production, Transport and Usage". To reinforce the IET position on system stress and the need for an Architect (Power Networks Joint Venture). From FPS 1, 2 and 3 which are on my www.eleceffic.com webspace Electricity flows from Alternator to Appliance at the speed of light and there is no storage in the wires. Thus, each Electricity system is always in perfect instantaneous Power balance (Generation Power = Delivered Demand Power) Any mismatch between Generation Power and 'Required' Demand Power (as would be at 50Hz) causes an excursion in system speed (frequency). Generation Power needs to be tightly matched to 'Required' Demand Power as a large excursion can cause instability and loss of equipment. Most generation plant is 'locked together' by synchronism and thus delivers or absorbs energy instantaneously to counteract a speed change (with automatic damping) - inertia. Most induction motors will also respond to damp frequency excursions. However, increasing levels of induction and DC Generation (DFIG-AC and AC-DC-AC etc), as used on Wind turbines, is not interlocked in this way. The system needs to be secured at all points for any single credible loss with secure active and reactive power flows and system stability (steady state and transient) maintained under all conditions (pre, during and post fault). Thus each AC system is a single large machine and one of the largest on the planet; with the prime movers connected to the demand by electromagnetic coupling, through a quite fragile system of wires. At the system Peak we are pushing nearly 85 million Brake Horsepower through that quite fragile set of wires!! The EU CE system gets to over 500mBHP
Stephen Browning – Written evidence (REI0007)
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As regards the questions and evaluating the worth and viability of future strategies for Electricity system configuration (FPS 22). I thinks this hits the various points. We need to determine what combination of Generation (Big+Little), Storage, Distributed Resources management, Interconnection trading, Ancillary services provision and Transmission/Distribution management will deliver the goods as regards safe, secure, efficient, and economic operation with reduced fossil fuel burn. All parts of the electricity business are involved; generation, supply, transmission, distribution, system operation and the market, together with the customer, in a commercial/technical framework in which the target can be hit while maintaining system security, quality of supply and accuracy of settlement. Better commercial and technical interfaces are required between member states and across Interconnectors between Electricity Pools. This forms the 'Smart Enterprise', incorporating Smart Grid and Smart Meter initiatives. A number of time series simulation studies of future plant mixes have been run using schedulers (my specialist area) including ' state of the art' Mixed Integer-Linear software. But, each run only gives a single definitive snapshot of the Generation (and demand management) profile for a single set of data. As we move through time, predictive and forecast data will change and that will occur more often as more volatile (variable and partly difficult to predict) plant joins the system. The main issue is the need to evaluate the various scenarios correctly; full nested time 'walk through' series iterative simulations (Commitment-Schedule-Dispatch-Outturn) in respect of the Power System, with Fuel supply allocation and emissions calculations. This involves both Market and Operator mechanisms in iterative tandem. As we move through time, predictive and forecast data will change within the forward models and the actual conditions will be applied to give the outturn, including reserve delivery. This needs to cover prediction of generation and demand (in total and by location), the matching of the totals and the overlaid actions to maintain Transmission and Distribution security (static/dynamic stability, pre/post fault overload and voltage risk). The system will be more 'volatile' than at present, especially where variable renewables and counterbalancing storage, interconnection and/or customer action cause power flow swings. It is the 'Sustainable Transformation' of all three energy sectors; Power, Heat and Transport, which is the big target for Energy Security, Emissions reduction and Cost. We have a lot of different technology which tries to approach this, but which combination will deliver the goods??. We can only work out the Smart Customer and Grid requirements if we have a view of where the Smart Enterprise is going. Thus we need to model the three energy sectors with different combinations of technology to see which is the best approach.
Stephen Browning – Written evidence (REI0007)
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The future Electricity system will be more dynamic and reliant on fast communication and data analysis to ensure system security and stability is maintained. It is probable that the level of instruction and monitoring required will mean that manual operation will no longer be feasible and that a high level of automation of Market and Operator (system operation) functions will be required. That obviously increases the risks from IT systems failures or attacks on same. ================================================================= I spent many years with the CEGB then National Grid, working in the fields of generation, system operation and the development of models for Generation Economics - Commitment, Scheduling, Dispatch and Ancillary services with the associated representation of Demand, Fuel, Market, Interconnection flows and Transmission security constraints. "The Future is out there somewhere; we just have to make sure we get the best one" "There are an infinite number of ways of running an Electricity Supply system badly" ====================================================================== Stephen Browning BSc(Hons) MIET MIEEE MEI Ex CEGB and National Grid UK GB Electricity Operations - Generation, Demand, Fuel and Market modelling Contributor to EU Smart Grids Technology Programme WG 2 - Network Operations 30 August 2014
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042)
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Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042) Introduction 1. The Carbon Capture and Storage Association welcomes the opportunity to respond to
the Select Committee on Science and Technology’s Call for Evidence on the Resilience of Electricity Infrastructure. The CCSA would be very happy to provide any further details on the issues raised below and would also welcome the opportunity to provide oral evidence.
2. The CCSA brings together a wide range of specialist companies across the spectrum of Carbon Capture & Storage (CCS) technology, as well as a variety of support services to the energy sector. The Association exists to represent the interests of its members in promoting the business of CCS and to assist policy developments in the UK and the EU towards a long term regulatory framework for CCS, as a means of abating carbon dioxide emissions.
General comments 3. The development of a commercial CCS industry and the establishment of a CO2
transport and storage infrastructure could deliver significant benefits to the UK’s industrial and energy systems by 2030:
Affordable decarbonisation of the power sector and industry – annual household bills could be £82 lower by 2030 with CCS in the energy mix5, and decarbonisation costs could be reduced by around £30bn a year by 2050 with CCS.6
Enhanced integration of other low-carbon energy sources – flexible CCS-generation would be complementary to inflexible or variable output from renewable and nuclear generation sources;
Energy security – through enabling the continued use of both indigenous and imported fossil fuels whilst reducing their carbon emissions;
Industry retention – enabling carbon intensive industries to retain their activities in the UK/EU rather than relocating in order to avoid carbon costs;
4. Given the time scales associated with developing CCS projects the period through to 2030 provides a very limited window within which the technology has to be deployed for the first time, commercialised and deployed at scale. If the benefits of CCS for the UK are to be realised then a clear and ambitious Government CCS policy is needed to maintain momentum and support a progressive roll-out of CCS. The actions necessary to deliver CCS at scale can be neatly divided along the timelines set out in this call for evidence, i.e. short term (pre-2020) and medium term (to 2030). Critically the short term actions are a necessary enabler of the medium term actions and must be delivered.
5 http://www.tuc.org.uk/sites/default/files/carboncapturebenefits.pdf 6 http://www.eti.co.uk/wp-content/uploads/2014/09/Highlight-Report-Carbon-Capture-and-Storage-20141.pdf
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042)
24
Short term (to 2020)
What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
5. Delivering the objectives outlined above requires the three main carbon reduction technologies to be cost-competitive, commercial and deployable under the electricity market framework. For CCS to be commercialised, the period to 2020 requires the delivery of the first two projects under the current CCS competition7 towards the end of the current decade. However, to deliver on this timeline the Government needs to negotiate the CCS competition contracts with pace and intent. The competition projects not only provide the evidence required to inform future investment decisions but will also establish the early CO2 transport and storage infrastructure that can be utilised by subsequent projects. The ability for CCS projects to utilise shared infrastructure is key to delivering cost-competitive CCS.
6. In addition to delivering the first projects the policies must provide enough confidence to prospective developers on the future market for CCS that investment in a second phase of CCS projects can commence in parallel to the development of the competition projects. Bringing forward this second phase is key to supporting the progressive, cost-effective, roll-out of CCS that is necessary to delivering the benefits of this technology to the UK.
7. The alternative approach of commencing development of second phase projects after
the competition projects have begun operation (i.e. 2020 onwards) would seriously jeopardise the UK’s ability to install significant CCS capacity in the decade to 2030 and threaten the UK’s electricity infrastructure resilience.
8. To deliver the CCS deployment timetable set out above the following steps are required;
Regulatory and policy clarity that clearly defines the long-term revenue streams which enable investors to recover their capital and operational expenditure.
A commercial framework that enables investment in shared-user ‘right sized’ CO2 pipelines to deliver economies of scale and pre-investment in storage site characterisation to provide CO2-emitters with the confidence to invest in capture projects. In particular it should be noted that geological storage site characterisation has a long lead-time, bears geological risk and has a high cost in proportion to the overall store development cost.
CCS needs to be placed on a level playing field with other relatively immature renewable energy sources. CCS should be explicitly supported in the EU 2030 Energy and Climate Framework as an essential part of achieving the European energy and climate change objectives. CCS will also benefit from a reformed and more effective EU Emissions Trading Scheme.
7 https://www.gov.uk/uk-carbon-capture-and-storage-government-funding-and-support#ccs-commercialisation-competition
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042)
25
Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure?
9. Delivering the two projects under the competition will demonstrate the commercial model, test the regulatory framework, establish strategic CO2 transport and storage infrastructure, provide cost discovery and expected cost reductions and deliver insights on expected performance of CCS in the UK. This will help inform the development of future policies that will bring forward additional CCS capacity.
Medium term (to 2030)
What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models?
10. Energy system modelling clearly demonstrates that the most affordable route to decarbonisation of the economy is through the deployment of CCS alongside the widespread deployment of renewable and nuclear. Modelling scenarios which remove CCS technologies demonstrate very considerable increases in the cost of decarbonisation. For example, the IPCC8 assessed a number of models and found that the increase in mitigation costs in scenarios with no CCS averaged 138%, which was a significantly greater increase than seen for scenarios without nuclear (7%), limited solar/wind (6%) and limited bioenergy (64%). In the UK the ETI has developed its ESME model which similarly demonstrates that CCS is the most “valuable” of the low-carbon technologies as the costs of decarbonising almost doubles by 2050 when CCS is not available.9 Further analysis of the ESME scenarios showed that by 2030 electricity prices in the UK were around 15% lower when CCS included in the energy mix compared to scenarios where decarbonisation targets were reached without CCS.10
What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
11. In addition to the contribution to decarbonisation and cost-competitiveness thermal power plants fitted with CCS have the potential to operate flexibly and in this regard are very much complementary to intermittent renewables and inflexible nuclear plant. Despite there being considerable value in low-carbon, flexible generation current policies will not deliver technologies like CCS with these characteristics. The primary policy support for low-carbon technologies is FiT CfDs, however these have only been designed as either “intermittent” or “baseload” contracts and there is no contract to incentivise the development and operation of flexible low-carbon plants. The
8 http://report.mitigation2014.org/spm/ipcc_wg3_ar5_summary-for-policymakers_approved.pdf. 9 http://www.eti.co.uk/wp-content/uploads/2014/09/Highlight-Report-Carbon-Capture-and-Storage-20141.pdf 10 http://www.tuc.org.uk/sites/default/files/carboncapturebenefits.pdf
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042)
26
Government did consider the development of “flexible CfDs” in the EMR White Paper11 however this has never been progressed. Flexibility of CCS systems has been demonstrated and validated, however in the absence of appropriate policies flexible CCS plants will not be built and operated at the necessary scale.
Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
12. The technologies used in CCS are largely mature and ready for deployment at commercial scale. The challenge to delivering CCS in order that its unique characteristics can contribute to electricity resilience is largely associated with the integration of the technology into novel value chains, testing regulatory frameworks and establishing a policy framework that enables a progressive roll-out of the technology over the period to 2030.
Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
13. The UK has clear potential to be a leader in the development of CCS. The UK had intended to be one of the first countries to develop the application of CCS to power plants and launched its first programme to deliver the technology in 2007 and expected to have its first project operating in 2014. However, the development of projects has not progressed as quickly as anticipated and the first operating power CCS projects are in North America. UK industry has taken around 17 projects to various stages of development and it is deeply disappointing that progress here has not been as rapid as expected.
14. The CCSA’s optimism on the future prospects of CCS in the UK is predicated in part upon the new framework that has been established under Electricity Market Reform. This framework is the world’s first that has the potential to drive the deployment of all low-carbon technologies; CCS, nuclear and renewables. While other regions have been more successful at delivering the first commercial-scale CCS projects EMR provides the framework which can enable the scaling up of the technology thereby delivering the benefits outlined above. However it must be noted that the EMR framework is not complete and this Government has still not established a CCS CfD, a CfD allocation framework for CCS or provided any clarity on the timing and volume of additional CCS projects that might be deployed. Until this work is completed the UK’s CCS potential will not be realised.
15. To date the policy framework – driven by the legally binding 2020 renewables target -
has strongly favoured investments in renewable energy technologies. The CCSA believes that this has been to the detriment of CCS and to our 2050 target. Looking
11 Annex B: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48130/2173-planning-electric-future-white-paper.pdf.
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042)
27
forward it is important that a more level playing field is established to support the investment in all of the low-carbon technologies. In this respect the CCSA is supportive of the Government’s position on importance of a technology-neutral approach in the EU 2030 energy and climate framework discussions.
16. While the focus of this inquiry is on electricity sector resilience it is important to note
that the development of a commercial CCS industry could bring significant application and benefits to industrial companies in the UK. Industrial consumers would benefit from the development of CCS not only in the provision of cost-effective, decarbonised electricity but also because CCS is in many cases the only technology that can be used to significantly reduce industrial process CO2 emissions, i.e. those emissions arising as an intrinsic part of the industrial process rather than from the combustion of fossil fuels. Fossil-fuels and CCS can also be an important source of cost-competitive low-carbon hydrogen which is expected to play an important enabler to the decarbonisation of a number of industrial applications. Longer-term the development of CCS could provide the UK with the opportunity to not only retain but potentially grow its carbon intensive industries as EU and global decarbonisation efforts continue.
17. Finally, the UK is particularly well-endowed with geological formations that are well
suited to store CO2. Analysis by the UK Storage Appraisal Project12 concluded that the UK could potentially store almost 80 billion tonnes CO2 which would be more than enough to meet the needs of the UK for the next 100 years. This provides a potential opportunity for the UK to “sell” CO2 geological storage facilities to European countries that do not have ready access to suitable geological structures.
Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects?
18. The UK has established Knowledge Transfer obligations on the two projects that are being developed under the current CCS competition. As these projects are still under development the outputs from these projects have not yet been delivered however they are expected to help ensure that the lessons from these first projects are effectively disseminated.
Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
19. As noted in paras 14 & 16 above the EMR policy framework has clearly stated that it will enable investment across all low-carbon technologies. However, to date there is still a significant amount of policy that needs to be developed before EMR is able to support the commercial deployment of CCS in the UK. In addition DECC has recently released a CCS Policy Scoping Document which is consulting on the framework needed to bring forward the next phase of CCS. As the CCSA develops its response to this consultation it would be happy to provide this information to this inquiry.
12 http://www.eti.co.uk/project/uk-storage-appraisal-project/
Carbon Capture and Storage Association (CCSA) – Written evidence (REI0042)
28
The view expressed in this paper cannot be taken to represent the views of all members of the CCSA. However, they do reflect a general consensus within the Association. 26 September 2014
City of London Corporation – Written evidence (REI0029)
29
City of London Corporation – Written evidence (REI0029) Submitted by the Office of the City Remembrancer Introduction 1. This submission provides the City’s views on the need for greater regulatory flexibility
and more targeted investment and calls for better planning of the delivery of capacity in the system. The submission concludes with a suggestion for a new approach to the capacity problem.
2. The City Property Advisory Team at the City of London Corporation works alongside
developers, utilities and telecoms providers in ensuring that the Square Mile provides the optimum environment for existing and new businesses. It is in the context of the City’s role in promoting the Square Mile as a world leading hub for business, that the City of London Corporation makes this submission.
3. The Square Mile directly competes with other cities to be the premium destination for
global business. One part of the City’s, and London’s, attractiveness to international business is the ability to provide the highest quality commercial buildings and services. A significant factor working against London’s position is exemplified by a recent World Bank Report which placed the UK as the 62nd out of 184 countries for getting an electricity connection on time.
4. The City of London's area has the largest electrical footprint (over 600 megawatts) in the
UK and demand for electricity in the Square Mile has greatly increased in recent years, owing, for example, to the widespread use of power intensive IT equipment and cooling systems.
Lack of Capacity 5. UK Power Networks (UKPN) is the District Network Operator (DNO) for London. It is
clear that its network in London does not have available spare capacity to cope with future demand. This poses risks to future development and refurbishment cycles because developers and property owners are unable to be sure of the availability of electricity capacity. Further uncertainty results from the fact that it can take up to 3 years for substations to be reinforced and installation works completed so as to have sufficient capacity to supply a new building.
6. Given that Ofgem’s existing regime does not incentivise investment ahead of need, new
connections generally occur on an ad hoc basis, responding to immediate demand. The difficulty of creating such new connections at the last minute is hampered by the physical characteristics of the City (such as utilities congestion under the highway. This is a further factor that creates uncertainty and results in a lack of capacity in the system.
City of London Corporation – Written evidence (REI0029)
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Resilience and Security - Generation 7. Recent research13 undertaken by the British Council for Offices has outlined that the
forthcoming closure of the UK’s legacy generation plant and lack of available new sources of generation has increased the likelihood of blackouts from 1 in 3,307 years in 2012 to 1 in 12 years in 2015. Moreover, the sector’s regulator, Ofgem, does not incentivise DNOs to modify and improve aging network assets. The City Corporation is concerned that a possible “black start” - where supply is suddenly unavailable across the whole of a network and needs to be restored - would severely affect the Square Mile and its ability to continue to operate as a business centre. We are also gravely concerned about the effect that such an event would have on London’s reputation.
Network Resilience / Power Network Distribution 8. As a regulated monopoly, UKPN is obliged to carry out a price control review every 8
years, which involves submission of their business plans to Ofgem, to determine future investment plans, and the overall revenues that UKPN is permitted to recover from customers. Under the latest price control review process, UKPN is required to consult with stakeholders and ensure that their views are represented in the final business plan. As part of UKPN’s consultation, the City of London provided information to UKPN on likely forthcoming developments. After considering the draft business plan produced at the end of this process, the City concluded that UKPN’s investment plans for the period 2015-2023 (which included the reinforcement of 6 existing substations serving the City of London) would have been sufficient to meet the expected level of required new capacity. This new investment would have increased the capacity of the City’s network from the existing 600MW peak load by 50%. However, following the submission of its business plan by UKPN to Ofgem, the regulator’s preliminary determination was to reject UKPN’s draft business plan. This has compounded the existing problems regarding lack of investment. Ofgem has proposed a 12% reduction in the UKPN’s overall spending plans for the period. This would mean a loss of money available for investment in central London of around £200 million. This is highly likely to have a significant impact on UKPN’s ability to undertake a suitable level of network asset replacement work in the period 2015-2023. Cuts in investment are likely to lead to more widespread and frequent network outages due to the age of network assets.
9. UKPN’s network serves the Square Mile, which generates 16% of London’s total output
and 4% of the UK’s total output. This is a major issue for the City, London and the nation. The Corporation believes that in this context the regulator should re-consider aspects of UKPN’s spending plans with a view to allowing the replacement of cable assets over a certain age as well as those serving key buildings and under key junctions and distributor roads. Whilst the City Corporation fully accepts Ofgem’s desire to keep consumer bills to a minimum, the Corporation remains concerned that Ofgem’s determination will not provide UKPN with the funding to ensure sufficient resilience can
13 http://www.bco.org.uk/Research/Publications/Britains_Energy_Gap.aspx.
City of London Corporation – Written evidence (REI0029)
31
be built into the City and Central London’s network to support the needs of business and residential stakeholders.
10. Furthermore, the City Corporation is concerned that the reduction in proposed funding
could affect UKPN’s plans for investment in greater network automation enabling the provider to switch power between substations and thus avoiding loss of supply to businesses and residents. Investment in such automation would do much to provide a more robust network for Central London.
11. In a further aspect of its preliminary determination of UKPN’s business plan, Ofgem has
reduced the amount of expenditure that UKPN will be allowed to make in installing deep level tunnels to house critical 132kv transmission cables. These operate at high voltage and deliver power to substations from the National Grid. If, because of Ofgem’s determination, UKPN is required to take the cheaper route and install such cables under the public highway, there would be a serious negative impact on traffic across London. In addition, placing such heavily powered cables under the public highway could pose considerable risk of catastrophic district wide network outages should one of the cables be disturbed by any of the many utilities companies that regularly dig up the highway. The City therefore considers it imperative that Ofgem reinstate this funding element in its final determination in December 2014.
Size of Connection 12. The planning process for large developments can take many years. In an ordinary case,
for example, it will take about 3 years. During the planning stage for large office buildings (whether in the Square Mile or beyond) there are often difficult negotiations with UKPN over the availability of power supply to the building. These negotiations arise for two reasons: (i) there is very little capacity in the system; and (ii) the work required to reinforce a substation such that it is able to supply the required amount of power often takes longer than the design and build of an office block.
13. A separate problem arises because there appears to be an unknown amount of reserved
capacity on the network which is currently unused. Some of the larger buildings in the Square Mile are now requesting up to 15MW, enough electricity to power a small town, which is largely to cater for trading floor operations. Developers (whether in relation to new build or to refurbishment) are likely to request large amounts of capacity because, given the difficulty of obtaining supply in a timely manner, they cannot sure what type of tenant is likely to occupy the building and so hedge their bets. The additional cost of reservation charges is borne by the business because they regard it as a way of mitigating the severe difficulty and uncertainty surrounding a future request for the supply of electricity.
14. UKPN has confirmed to the City Corporation that UKPN would consider a scheme where
capacity could be sold by a building back to UKPN for use elsewhere on the network. UKPN maintains, however, that it is constrained from progressing this idea because the existing regulatory regime prevents it from engaging in such arrangements.
City of London Corporation – Written evidence (REI0029)
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15. The City Corporation considers that, given the scarcity of available capacity in
substations serving the Square Mile, UKPN should be permitted to take an active role in policing the size of the connections which developers and occupiers are able to retain when it is beyond their requirements.
16. UKPN should adopt the model used by Consolidated Edison, the electricity network
operator for New York City, whereby developers are told what size connection they are allowed based on industry standard formula (10Kilowatts per sq m), and the amount of capacity taken is therefore dictated by a calculation of watts per square metre of the whole building. Developers are able to reserve extra capacity for future expansion, if they agree to pay the cost of additional power at the start. Network capacity is, however not reserved, and Consolidated Edison will agree to invest in the network to create the additional capacity at an agreed point in time, providing the developer exercises the option for additional power at a contracted point in time. If the developer does not exercise its option, Consolidated Edison retains all monies paid by the developer and the capacity is released for use by other customers.
Investment ahead of need / timing of investment 17. The scenario set out above leads the City Corporation to conclude that there is a failure
in the regulatory framework that prevents DNOs investing ahead of need. The City believes that in an area with the largest electrical footprint in the UK investment ahead of need should be permitted.
18. The City of London, London First and the City Property Association commissioned the
“Delivering Power” study14 in April 2012 which found that UKPN is not incentivised to invest ahead of need under Ofgem’s current regime. The existing system promotes a “just in time” approach. The failure to allow investment ahead of need constrains developers’ ability to ensure network capacity for new developments. Consequently, businesses and developers suffer from uncertainty in crafting their business plans, delays to new developments and risks to their business.
19. Together with Westminster City Council, GLA, City Property Association, Westminster
Property Association and London First, the City Corporation has engaged with UKPN to feed into their business plan and called for central London to be allowed greater flexibility in investing in spare capacity.
20. In August 2013 the City submitted to UKPN’s business planning consultation details of
forthcoming developments in the Square Mile. The timing and distribution of the investment remains key - to ensure that capacity is delivered in a timely manner so that it does not pose risks to the delivery of new development. There must be better predictability of UKPN’s investment path. The City Corporation has amended its Planning Policy to ensure that developers engage with UKPN as soon as possible.
14 http://www.cityoflondon.gov.uk/business/economic-research-and-information/research-publications/Documents/research-2012/Delivering%20Power.pdf).
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Developers must include the building’s likely electricity footprint in the planning application so that this information can inform UKPN’s future demand modelling for network upgrading. This approach can make, however, only a limited impact on the overall problem.
21. Engagement, by the City Corporation and others, with developers has shown that they
are willing to pay more if it means that their connections will be delivered faster. In certain cases developers are prepared to pay for full reinforcement of substations, despite only using a fraction of the new reinforcement and accepting that refunds (calculated on subsequent use by other parties) may be paid at a much later date. This highlights how desperate developers are to secure electricity supplies for their building. It is therefore likely that developers would support any future developer-funded proposal to facilitate investment ahead of need.
22. Ofgem has argued that DNOs can invest ahead of need under Section 22 of the
Electricity Act 1989. This provision allows developers to act as a consortium which may be effective on brownfield sites where there are 3 or 4 major developers, but it would not be practical in areas such as the City of London or other urban areas where there is a high level of continuous growth and with, for instance, over 70 developers operating across 120 development sites with varying timescales and developers requiring electricity connections at different times.
23. The City Corporation supports the Mayor of London’s representations to Government
on investment ahead of need. In June 2014, following discussions with the Mayor, senior ministers from DECC and BIS agreed to consider a proposal that could operate alongside existing regulatory arrangements. The proposals considered that the initial investment needed from DNOs would be funded to enable network reinforcement / planning of connections ahead of need. Ofgem and DECC agreed they would be willing to discuss any proposals so long as they do not affect consumer bills and must be able to be adopted on a UK-wide basis. If the Government is considering legislative moves in this area, it is likely to require funding from developers operating in defined development zones. The delineation of such zones will rely on local government to provide projections of likely forthcoming developments. The success of any scheme will depend on choosing areas of continuous existing and planned high office development where there is known to be high utilisation of DNO assets, and a lack of spare substation capacity in the local network (such as the City of London and the Central Activities Zone as defined in the London Plan). The City has volunteered to be the test bed for this proposal given rapid take up of substation capacity utilization by developers presenting marginal risk.
24. However, the starting point for the verification of any case for investment ahead of
need will be a clear overview of available DNO substation capacity in areas of high development growth. Regrettably this data is currently unavailable. Ofgem and the Government should ensure that DNOs make this information publically available. It would be important to consider this data alongside information from developers, market details and Local Authority information (in London at the GLA level as well as at
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borough level) in determining appropriate areas. The City, for example, has robust information on the timescales of forthcoming developments.
25. The City has met with Ofgem and suggested that the link between local authorities and
DNOs should be restored to allow UKPN to be able to compare future investment with local authorities’ development projections, to coordinate connection works more effectively, and install spare ducts in areas of expected need. Areas such as the Square Mile benefit from high levels of continuous development growth and the City maintains a development pipeline that can pinpoint where large loads will occur. Based on this suite of information it can be argued that there will be a very high utilisation of investment in capacity ahead of need in such areas.
19 September 2014
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Committee on Climate Change (CCC), Energy Technologies Institute (ETI) and the Resilient Electricity Networks for Great Britain (RESNET) project – Oral evidence (QQ 124-138)
Evidence Session No. 11 Heard in Public Questions 124 - 138
TUESDAY 9 DECEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Baroness Sharp of Guildford Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston
________________________
Examination of Witnesses
Matthew Bell, CEO, Committee on Climate Change (CCC), Dr David Clarke, CEO, Energy Technologies Institute (ETI), and Professor Kevin Anderson, representing the Resilient Electricity Networks for Great Britain (RESNET) project, University of Manchester
Q124 The Chairman: Welcome. We are grateful to you for joining us this morning as we take further evidence on our inquiry into electricity resilience in the United Kingdom.
Would you like first of all to introduce yourselves, and if you would like to make an opening
statement, please feel free to do so? I should just alert you to the fact that we are being
recorded, so everything you say will be on the record. Thank you.
Dr Clarke: I am Dr David Clarke. I am Chief Executive of the Energy Technologies Institute, ETI. We are a public/private partnership carrying out design and analysis around the UK energy system out to 2050, and then investing in major technology demonstration and engineering demonstration projects to try to address the challenges in delivering those solutions.
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Professor Anderson: Kevin Anderson, I am Professor of Energy and Climate Change at the University of Manchester and deputy director of the Tyndall Centre for Climate Change Research and, for my sins, today I am the principal investigator on a project looking at the resilience of the electricity network in Great Britain.
Matthew Bell: I am Matthew Bell, I am Chief Executive of the Committee on Climate Change, which is the Parliament and the Government’s independent adviser on issues related to climate change and climate budgets.
Q125 The Chairman: Thank you very much. If none of you wants to make an opening statement shall I start with a rather general first question? Would you like to tell us how you think that electricity resilience in the United Kingdom compares to that in other countries in Europe and North America? I am sorry; I have the wrong one again. Sorry, start again. I am always doing this. How do you expect climate change to impact on the resilience of the electricity system?
Matthew Bell: Shall I start off and others can jump in? It is worth saying, to start off, that there are at least three ways to think about the resilience of the electricity system as it relates to climate change.
The first of those has to do with protecting the electricity network, generating stations, substations and the extent to which it is resilient to the effects of climate change, such as flooding, high winds, weather and those kinds of things. So one issue the Committee on Climate Change and the Adaptation Sub-Committee has looked at is: is the network resilient to both climate change-related events and weather-related events?
There is a different issue, which is about meeting changes in demand that we foresee over the next 20, 30, 40 years—changes in demand because, for example, cooling becomes more important, changes in demand related to electric vehicles, changes in demand related to electricity for heating. Demand might change. Is the network and is the infrastructure we have resilient to that?
The third issue is in the generation of electricity itself: one of the recommendations coming out of the Committee, and one of the recommendations in the Government’s carbon budgets, is increased use of renewables, some of which are intermittent, so there is increased intermittency of generation—does that have an impact on the resilience and our ability to meet demand?
So the resilience of the network, when we are thinking about it, falls into each of those three categories, and what you do in each of those three areas has an influence over how resilient the network is. I will pause there, and then clearly if there are questions on any of those three areas or anyone else wants to come in—
The Chairman: Would either of your colleagues like to come on this?
Dr Clarke: From my point of view, I would like to emphasise the clarity and distinction between the questions of how we expect climate change to impact versus any response we choose to put in place to meet climate change targets in terms of energy system targets. As Matthew just highlighted, certainly in terms of climate change and the potential that we see there, there are two key issues that we had identified in the context of the UK, one of which is the potential for warming and hence an increase in demand particularly for air-conditioning in terms of electricity loads. Also, there is the potential risk for cold weather in
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the winters, and how long we may see cold spells, what the duration is and what the intensity is. I think that is more uncertain. But those are what I would very much classify as effects that we will see as resulting from climate change. Then there are clearly the targets that we set nationally in terms of what policy measures we want to implement, and what energy system designs we adopt as a consequence. Those two things need to be treated quite differently. One we have to react to and deal with; the other one is of our own making, in essence. We are choosing what kind of energy system we want to put in place.
The Chairman: Would you like to speculate on the first of those, the effects that climate change will have on demand patterns?
Dr Clarke: From my perspective, the air-conditioning position is one that we need to be very conscious of for two reasons, one of which is that we are seeing warming in summers. Reports even today suggest we are going to continue to see warming in summer spells. We are seeing increased rollout of air-conditioning in new build developments, in cities in particular. That is happening already, and clearly the consequence of that could be a trickledown effect to a broader section of the economy and broader sections of the residential population in terms of that happening. The demands that that places on the system are quite significant compared to most loads in a house today. I am talking about residential properties. The cold weather situation is far less clear as to what will happen and as to whether we will actually see deeper, longer cold spells or not. That is something that the Met Office are probably best placed to advise on from their perspective, and the Tyndall Centre.
Professor Anderson: I agree with both my colleagues. You can split this into supply and demand, and I am going to focus, just initially, on the demand side. Again, there could be additional air-conditioning load on the grid. To give us some sense of what that might mean, we currently consume, very approximately, about 350 terawatt hours of electricity in the UK. That is our final energy consumption. That might not mean a lot to some of you, but it might mean something to others. But the air-conditioning load from some of the work we have done within our project RESNET suggests that it could look similar to total current electricity demand. So air-conditioning load, as we go forward through the warmer climate, could be as big as the total electricity demand today.
If you add to that a lot of discussion, which some of you will no doubt have heard, about electrifying cars, at the moment cars consume—in terms of diesel and petrol, including light vans as well—about the same amount of energy as the total grid, again about 350 terawatt hours. If you then look at domestic heating in the UK, which the previous chief scientist at DECC, David MacKay, was talking about having significantly put on to the grid, principally through heat pumps, at the moment that is about 350 terawatt hours.
So if you think about this, this is a grid that is four times larger—if you put heating, air-conditioning and transport on the grid—than the current electricity demand. If you then want process heat for industry, for cement making, for steel industry and so forth, that is also about another 350 terawatt hours. So people keep talking about electrifying things, and even if you can become much more efficient and maybe reduce half of these loads—nevertheless, the size of the grid for these futures would still be very much bigger than today. I would suggest that currently the grid provides about 20% of our energy, and if we are serious about climate change then it needs to move towards 60% to 80% of all electricity
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demand. It needs to be three or four times larger than it is today, or we need to become phenomenally more efficient than we are now.
If we are honest about this, we do not know what the wind conditions are going to look like in the future. We can say something about mean temperatures across the UK. We are very poor at understanding what those extremes will look like, and infrastructure is very susceptible to the extremes as well as the means. The means are important; the ongoing warming has a big impact on the grid. Nevertheless, the extremes are also important, and we are not good at understanding those at the moment.
Similarly for wind, we have a very poor understanding of the extreme impacts of wind, and we have a very poor understanding of the direction of the wind going forward. Wind is interesting to think about. Even if the wind speeds only go up a little bit, the damage is roughly a cube law. You increase the wind a little bit and the amount of damage goes up by a cube of that. So there are a lot of unknowns about the future.
If you want to build resilience into that, you have to bear in mind that we do not know, first, what the grid is going to look like in terms of its demand profile. If we are serious about climate change, basically we have to electrify a huge proportion of the UK energy demand, and that has to be played out against the fact that, if we are really honest about this, we do not understand what the climate impacts will look like in terms of important characteristics such as wind, rainfall and temperature. That is probably not helping you make a very clear picture of this, but we need to be honest that the future is incredibly uncertain, both from a climate perspective and from what we are going to do in terms of our infrastructure itself.
Q126 Lord Willis of Knaresborough: Can I follow that up with a simple question, because it is a very depressing picture you have just painted? What I would like to ask all three of you, but particularly you, Professor Anderson, is whether you feel that, given the current government policy in terms of climate change that fits into international and global policy, the Government’s policy is sufficiently clear in order to maintain resilience, certainly up to 2050?
Professor Anderson: There is lot in that question, but the first thing is—and we may have some disagreement about this—that government policy on climate change domestically is not consistent with our international commitments. I have made this point repeatedly to numerous committees. You could drive a Maersk ship sideways through the gap between the two of these. So what we are agreeing to do domestically in terms of our mitigation efforts are completely inadequate for dealing with the 2°C characterisation that we often sign up for internationally, and we will again this year in Lima, and no doubt again in Paris next year. There is a big difference between those two. If you look at our domestic targets, we are probably developing policies that are broadly in line with those targets, but if the rest of the world did something similar to that, and it is not doing even as much as the UK at the moment, or at least many countries are not, then we are talking about 3°C or 4°C future temperature rises, which are very, very large indeed and, according to the CCC’s definition, which I would agree with, extremely dangerous.
Lord Willis of Knaresborough: You are saying that this disconnect between international commitments and domestic policy is something that has to be addressed and something that this Committee, as part of its response to resilience, should in fact put in because it is fundamental to resilience.
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Professor Anderson: It is, and it is not just our policies; it is that the framing of climate change domestically is incompatible with our framing of climate change internationally. We have much weaker sets of targets domestically than those that we imply—that would be perhaps the best language to use—internationally, when we say, “We are definitely going to stay below 2°C and make all efforts to avoid 2°C temperature rise”, and yet our policies are much more in line, and our domestic targets, with a 3°C to 4°C temperature rise difference. So this disjuncture has been there for a long time. Lots of climate experts are fully aware of this but it is something that has been kept relatively quiet.
Matthew Bell: It is just worth, on that specific issue of resilience up to 2050, again going back to this distinction between the impact of both weather and climate-related events on the network, and some of the things that Kevin was talking about, this increase in the size of the network and the generation that we have to have. We were talking about wind and things like that, but if you look at weather-related incidents on the network today, the latest report that the Adaptation Sub-Committee has published says that weather-related incidents accounted for about 35% of annual disruptions to electricity distribution networks between 1995 and 2010, so over that 15-year period. That is things like wind, flooding and so forth.
There are currently, for example, about 700,000 homes and businesses, three water treatment works, one hospital, all of which are relying on about 57 substations that are in areas of high or very high likelihood of flooding. There is a risk there in terms of resilience of those types of things. The Adaptation Sub-Committee then looked through all the different sectors of the economy, including electricity distribution, to look at what was being done about those types of issues. Electricity transmission distribution today was the only sector that the committee felt had adequate measures in place to protect against what is foreseen to happen right now. It looked at water, electricity and a whole number of other sectors, and it felt that the electricity distribution and transmission infrastructure, as it currently is and with our current understanding of risks, is doing a lot and is adequately resilient.15
That follows on in some ways from the 2007 floods, and from the Pitt review. A lot of recommendations came out of that about investment that was necessary. The one caveat around that is clearly that Ofgem have just completed, in the last 10 days or so, their price-control review, which sets out what companies are allowed to spend on some of these things. We are still reviewing that in terms of the business plans that were put forward and the investment that was put forward. That is one aspect of the issue, and a serious aspect.
Certainly , as Kevin was saying, things like wind speed and stuff like that are very unpredictable. We are not sure what is going to happen, but that is one side of the issue. The other side of the issue, around what is necessary to meet the statutory domestic targets of around an 80% reduction in emissions by 2050, then involves bringing on the electrification of vehicles and bringing renewables on to the grid. That involves very significant issues and significant uncertainties, and that is part of what clearly has to be managed going forward in order for us to understand the costs. Certainly there are other countries elsewhere in the world where renewables, electric vehicles, all those things are a greater proportion of the grid than they are in the UK currently, but we will be going to levels that are even higher than those that have been achieved so far.
15 See Committee on Climate Change, Adaptation Sub-Committee, “Managing climate risks to well-being and the economy: 2014 Progress Report”, figures quoted here appear on page 69.
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Q127 Lord Peston: If we place the whole subject within the context of system theory, then we would regard resilience as meaning adaptability to an unexpected shock. There should not be a resilience problem to the mean of the system, which is the point that Professor Anderson is making. Am I right?
Professor Anderson: Yes. Yes, of course, the mean is changing. So if you talk about the 2003 heat wave, there have been quite a lot of people suggesting that by 2030—with a lot of uncertainty again and caveats put on this—that could be the norm in the UK. That was a very extreme event and if you imagine the air-conditioning load that will be there you could argue that is an extreme that becomes the new mean. One of the big problems here is that we are not sure of that.
Lord Peston: I can understand that well, but that is, if you like, taking us to the next level up in terms of the difficult theory that we are dealing with anyway. What concerns me is where we know broadly what is going on, but only broadly, there should not be a problem, should there? Rational decision-makers should be able to deal with what they know is going to happen. The problem is: is the system capable of dealing with what we do not know is going to happen, to put it crudely? You could use more sophisticated language. What is your view on that? Are the people taking the decisions capable of showing resilience where they need to?
Dr Clarke: No, that was the comment I was going to make within the context of the last question as well, which is I think you need to be very cautious about asking a question such as, “Do we have policy that is going to deliver a 2050 resilient system?” We spent millions, as did many other people, including National Grid, on looking at what would be the optimum design for a future UK energy system and electricity system. I can guarantee you, if you put me on the spot and said, “What will it look like in 2050?” whatever answer I give you will be wrong. Uncertainty and statistics say it will be wrong.
If you ask me what it is going to look like in 2030, it is going to be pretty difficult to tell you. So for a broad, all-encompassing, “Is policy adequate?” yes or no statement, the answer is almost certainly, “For the very short term, probably yes. In the very long term, no, it is not”. “Can it be?” “No”. So you have to be very cautious about this policy piece for a number of reasons, one of which is just the sheer uncertainty, and the second one, as Professor Anderson highlighted, is if you assume you are going to electrify the entire UK energy system—by which I mean power, heat and transport—by any date you choose in the next 50 years, the answer is you are not going to do it. The reason you are not going to do it is that it is too expensive and there are many alternatives that are far cheaper. You have to look at the combination of power, heat and transport for exactly the reasons that have been articulated, which is that to build a system that could deliver 350 terawatt hours of heat, which is a challenging load for the UK, you would have to build an entire new National Grid. Cost? Quarter of a trillion, that kind of number.
To give you another piece of context, if you think you are going to deliver heat in the way that we all understand heat today, where we have a gas boiler in the main, or an oil boiler, or a coal fire that you turn on and off, you cannot do that using electricity. This is a simplistic view, but on 18 December 2010 gas demand on a Saturday morning in the UK when it was very cold went up by 132 gigawatts in less than an hour—in other words, more than the capacity of the National Grid was turned on in terms of gas heating in one hour. In the next
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60 minutes it went off again, because all the houses are warmed up and it came straight back down.
So this is my point: you have to look at this as a system and look at how you would deliver the system in the future, and in that context you can start to see affordable alternatives. All the design work we do suggests that to meet the 2050 targets that we have set ourselves involves of the order of 1% to 2% of GDP additional to a kind of business-as-usual, no-climate-change-targets kind of world. The whole point about the system piece is absolutely correct, but it is very important that we do not constrain ourselves into a mindset saying, “It is an electric system, end of story”. I think we have to look at this as being a question of how you deliver across power, heat and transport and utilise all the waste heat that comes off various industrial processes, off power plants, to deliver heat in the future, rather than simply focusing on delivering electricity into heat, because if we do, the system will not do it at anything like an affordable level.
Q128 Viscount Ridley: This follows on from what Dr Clarke was just saying. Leaving on one side for a moment the question of floods and winds, because we have an issue as to whether we are talking about weather or climate there, whether having adjusted to weather we can cope with climate change, most of what I am hearing suggests to me that three-quarters of the resilience problem that we face in the long term comes from climate policy, not from climate change. In other words, it comes from the desire to go fully to electrification and so on. Now, Professor Anderson said that there could be a 350 terawatt—presumably per year?
Professor Anderson: That is what we consume per year, yes.
Viscount Ridley: Yes, in a year, exactly. You say that there could be such an increase from air-conditioning alone. What are the assumptions behind that? How much temperature increase are you expecting to see and how much rollout of air-conditioning? Anyone can throw a number out, so what are the assumptions that have gone into that calculation?
Professor Anderson: The project is still ongoing and with air-conditioning we were looking at more extreme temperatures. Having said that, I used half the number that we have come up with so far. All I can say is that the air-conditioning load looks very large. Some of our very—
Viscount Ridley: What temperature assumptions?
Professor Anderson: We are talking about the more extreme ends of the climate change realm. So if you talked about us globally being unsuccessful on climate change, which would be the current track, then probably 3°C to 4°C global average, and then looking at how that played out within the UK.
Viscount Ridley: What does that say for the UK?
Professor Anderson: I would have to go back to look at the details of how that came out for the UK.
Viscount Ridley: But it was more than 3°C to 4°C.
Professor Anderson: No, we would probably be somewhere near the average, I would have thought.
Viscount Ridley: So 3°C to 4°C over what period?
Professor Anderson: This would be playing out to 2050.
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Viscount Ridley: By 2050, 3°C to 4°C?
Professor Anderson: This analysis goes out between 2050 and 2080. What I am trying to say is that there are many uncertainties as to how climate change will play out in that period, not least what our emissions will be. So what we are trying to look at for air-conditioning load is what the extreme would look like. The reason for this was to test the grid and then to start to say, “How could you come back from the extreme?” First, the temperatures may not be that bad. Secondly, we may significantly improve the housing infrastructure. So there are a whole suite of things we can do and if you put some of those in place, assuming the worst end of climate change, that brings you down to 350 terawatt hours. There is no doubt that there are other things that we can do, and are, looking at to try to bring it lower than that. Also, we normalise those sorts of practices. It is not as if you just have to have that to live. You normalise living in those sorts of properties. Most of us here were brought up in houses that we would never warm to the levels to which we warm them today, and of course most of us here probably do not air-condition our houses today. So how we respond is not just relating to temperature. How we respond relates to the new norms that we put in place.
When we looked at those collectively—as I say, this work is ongoing—then it looks as though the air-conditioning load could be very large. So what we need to be able to do, because we are working with National Grid, is to let National Grid know that that is a potential big impact. For them, they are not so interested in the terawatt hours; they are interested in the peaks, because of course this occurs primarily in the summer. The actual impact on the grid is enormous because it is not spread evenly over the year, quite obviously. It is spread across, principally, the summer periods, and that is a real problem for National Grid.
Viscount Ridley: Looking at Mr Bell for a second here, am I right in thinking that contrasting with 3°C to 4°C over the next 35 years, which Professor Anderson has mentioned, the warming over the last 35 years has been about half a degree or less?
Matthew Bell: Yes. We have not seen warming of 3°C to 4°C over the last 35 years. That is correct.16
Viscount Ridley: Exactly. Why this sudden jump this year?
Professor Anderson: We do not have any graphics here, but here we have the CO2 emissions in the last 50 years, here we have the CO2 emissions currently and here is looking at trends. CO2 is a greenhouse gas—you link the two together and that gives you something that links the temperature.
Q129 Lord Wade of Chorlton: In a way that discussion you have just had was the sort of discussion that I wanted to have, because I must tell you that I am sceptical of the Tyndall Centre. They always take extreme positions. I have had experience with them at Manchester in the past. Again, I ask you the question in a way that has just been asked. The point is that the temperature has not gone up. There are an awful lot of people who might believe like
16 The International Panel on Climate Change (IPCC) expert scientific report (Fifth Assessment, 2013) “Summary for Policymakers” states that “The globally averaged … temperature data … show a warming of 0.85 [degrees] C over the period 1880 to 2012….Trends based on short records are very sensitive to beginning and end dates and do not in general reflect long-term climate trends. As one example, the rate of warming over the past 15 years [is] 0.05 [degrees] C per decade … [which] is smaller than the rate calculated since 1951 of 0.12 [degrees] C per decade”. quoted from page 5 (at: http://www.ipcc.ch/pdf/assessment-report/ar5/wg1/WG1AR5_SPM_FINAL.pdf)
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you do, but there are an awful lot of people who do not believe like you do. Why are they always wrong and you are always right? What evidence do you have? You have none that proves that your concepts are right and everybody else is wrong. Maybe temperatures will not go up. I am much more inclined to agree with Mr Clarke’s concept and to think that to make sudden decisions now to solve problems that may never appear is something that you would never do in a business. You would never sensibly invest money to say, “Look, this is the worst situation that may happen in 20 or 30 years’ time, so I am now going to borrow all this money to solve a problem”—it might never come. Surely the way to deal with these issues is to have a plan that you can deal with them if the problem arises and, as Dr Clarke rightly says, we adopt a system that is more adaptable as time and circumstances change. At the moment there is no proof that what you are saying will ever happen.
Dr Clarke: Can I just make one comment about the system adaptability piece before we perhaps pick up on that? I think it is very important that, if you adopt an approach that says, “We have a system and we are seeking to adapt it”, we should understand the implications of how we would adapt it and understand those early. You do not want to be making it up on the fly in 2030 and making billion-pound decisions at that point without the evidence to know what you are doing and why.
Lord Wade of Chorlton: The way I understood it was that if you were to make a decision that these changes are going to have to be made in the future then some fundamental changes need to be made in our policy at this stage. We have taken evidence already that if we assume that there is going to be a big serious problem from carbonisation, we should perhaps change how we produce temperature. Maybe we should spend much more on trying to produce energy in a different form and invest into those activities rather than trying to solve the carbonisation problem. In other words, if I knew that some problem was going to arise as a result of something that I did not really know, I would say, “Is this the best system to be using to cope with that problem if it arises?” Maybe it is not.
Dr Clarke: What I would want to do now in my world, which is exactly what we try to do, is to be testing possible designs, which is important from an engineering point of view. Why? To do these big demonstrations, like CCS demonstrations and so on.
Lord Wade of Chorlton: Absolutely, alternatives. Correct.
Dr Clarke: So it is important we test—
The Chairman: Can we hear from Professor Anderson, please?
Professor Anderson: If you could give me some evidence outside the Committee about the extremes that you think we have taken, I would be happy to respond to those and see whether I would agree or not.
The second point is that I am not interested in your, anyone else’s or scientists’ beliefs, I am interested in conclusions. I am not sure what the general public think about quantum mechanics and I am also not sure what the general public think about cancer treatment, but I would probably go to the specialist for both of those. Similarly, you may well be right along with other people who take—I do not know about your background—a non-scientific approach to concluding some scientific issue. But, by and large, I would take the views of the experts. Looking at what other evidence is out there from the majority of climate scientists, they broadly hold to the position that was demonstrated very clearly in the recent Intergovernmental Panel on Climate Change reports. You may well believe that they are
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wrong. I will go with the scientists’ and the experts’ conclusions, rather than the beliefs of yourself or indeed other non-experts in that area. You can choose which set to go to. You can listen to the astrologists or the other people that may give you health treatment, or you can go to the experts. My personal view is to go to the experts. We may differ on that.
Q130 Lord Broers: Perhaps I can follow up on that. I am an engineer. I am used to large calculations. I am quite an expert in that, and I know that it is extremely difficult to draw up boundary conditions and to understand what you are doing. I have looked at the overall temperature thing. I can see that you can come up with some credible models for the overall model of the atmosphere and predict temperature increases. But you said yourself, just now, that you have a very poor understanding of how you will predict weather and violent weather, and yet the panels have made confident statements that the weather is becoming more violent. So you have contradicted yourself. Now, can you—
Professor Anderson: Who says it is becoming more violent?
Lord Broers: I hear it all the time.
Professor Anderson: No, not the panel. We are not saying that.
Lord Broers: We have it in our evidence here. I could read it out. I will not find it now. There is evidence here that we are already seeing floods consistent with the projected consequences of climate change, and storms highlighted against the cost, damage and disruption. It is all in here. So this statement is made quite often. It has always baffled me quite how you calculate the weather changes and the likelihood of storms, when you have relatively small changes in temperature. So my more constructive question is: is enough being done to improve these models?
Professor Anderson: You ask the modellers and they will always want a larger computer. Certainly, the models are improving. I am not a modeller. I am not a climate change modeller. I am an engineer, too. One of the big problems is you need to bring models down to a level where they can give you some useful information at smaller grid square areas, so smaller geographical areas. At the moment, they are reliable at larger grid square areas, but if you are trying to bring them down to understand infrastructure issues in particular parts of a country, or even a country as small as the UK, it is very challenging to do that. So the models need to be improved and, indeed, the new suite of models that are coming out will give us better robustness at smaller grid squares. But if we ever expect to be able to predict storms, what will happen in particular months within 2050 or 2060, then we will be sorely disappointed. We will not be able to give that sort of output. But we know that we are putting more energy into the system, so there may be small temperature rises, but the energy increase in the system is very large, and that energy generally plays out in a whole series of events, with increases in means and also increases in extremes.
I somewhat take umbrage with your saying that we are always talking about the extreme weather now being related to climate change. I read a lot of the science reports, not the ones in the press; I am not interested in what the journalists tell us. The IPCC are incredibly careful in the language they use. No doubt, if you hunted through the several thousand pages of documents, you can find the odd exception but, by and large, the IPCC and the climate change community have been very careful in the language it uses. It does not ascribe, for instance, Sandy or Haiyan, or indeed what happened here in the UK last year, to climate change. It may well say they are exacerbated by climate change.
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Lord Broers: I wonder if I am being given the wrong papers. I am reading here that the Adaptation Sub-Committee of the Committee of Climate Change stated in its 2014 progress report: “The global climate has already changed as a result of manmade greenhouse gas emissions. Here in the UK, land and sea temperatures have increased, sea levels have risen, and rain storms appear to be intensifying. Last winter’s floods are consistent with the projected consequences of climate change, and the storms highlighted again the cost, damages and disruption that extreme weather can cause”.
Professor Anderson: I would agree with all of that. There is nothing—
Matthew Bell: Given that that was my organisation that said it, let us—
Lord Broers: Is that not predicting that this is going—
Matthew Bell: Let us try to be clear. I think Lord Ridley is very helpful in mentioning climate and weather, and being clear about these things. There are some changes that scientists have ascribed to climate change and manmade climate change to do with—as you were quoting—sea level rise, changes in temperature, those types of things. They have been linked as well to increased storms. Increased sea level, temperature, sea level rise, those are measurable events and you can have a discussion about them. What the quote that you read out does not say is that a particular flood, or a particular storm, or a particular high wind event has been caused by—
Lord Broers: “Last winter’s floods are consistent with the projected consequences of climate change”.
Matthew Bell: Are consistent, that is right, yes. So the—
Lord Broers: What does that say? It says, “Last winter’s floods are consistent with the projected consequences of climate change”. This is the Committee of Climate Change that said that.
Matthew Bell: The modelling indicates that if you have higher sea level rises, then the chances are more probable that you will get more flooding. But it does not say particular flood—
Lord Broers: “Last winter’s floods”.
Matthew Bell: To bring this back to the issue of resilience, those types of activities, whatever their cause, the question is: is the electricity system resilient to them? Going back to some of the things that I was saying earlier, is the electricity network resilient to flooding, high winds, those types of things, whatever their cause? It is important that we understand that, and that is partly, clearly, what the Adaptation Sub-Committee—
Lord Peston: I am sorry to interrupt. I would like to hear the witnesses answer the questions. This is not about an argument backwards and forwards.
The Chairman: That is fair comment. I think we would like to hear from Mr Bell. Then I wanted to ask Lord Ridley to come to the next question. But if you would like to complete, Mr Bell, I am sorry you are being interrupted.
Matthew Bell: Just to finish that thought, there are some things that the climate change scientists and the climate change models ascribe quite closely to climate change—things like sea level temperature, sea level rise, air temperature. There are other things where the
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uncertainty is much greater, which is a lot to do with wind speeds, as Kevin was saying, flooding, lightning storms, all those kind of things, where all the climate scientists, I think, would agree that there is a great deal more uncertainty around the links and exactly how they happen. The issue of resilience is one of whether the networks and delivery of energy and electricity to households and businesses are resilient to those types of unpredictable events. Also, over the next 30, 40, 50 years, are we doing the types of activities that David was suggesting: testing the technologies, starting to embed the technologies and bringing the cost of those technologies down, consistent with what the Committee on Climate Change would say is the most cost-effective path to get us to where we want to be in about 2050?
The Chairman: Now we must move on. Lord Ridley, you were going to ask the next question.
Q131 Viscount Ridley: It follows closely on from what we have just been discussing, because we want to know whether there are adequate plans in place to ensure that the electricity system can deal with the impacts of climate change. It is important to distinguish here between, on the one hand, the impacts of climate change policy, which we have briefly talked about and, on the other hand, the impacts of weather—as you said, 35% of current disruptions are caused by weather and will go on being caused by weather. We can adapt to those and we can adjust to those. What is the extra work that needs to be done for, say, a 10% increase in wind speed—maximum wind speed, presumably—or whatever percentage you think is likely? What is the extra work that has to be done because of a change in sea level or a flood risk that would not be done anyway to cope with weather and give you a margin of error?
Dr Clarke: From our point of view, from an engineering perspective, in terms of the answer on that, we have been funding a project recently to look at hazards to the UK energy system, and the message we are getting back from that is that, fundamentally, there are good systems in place nationally, with individual major companies and with government. There are good systems in place for engineering—I will call it that—related risks around particular weather events and the consequences of an increase in a particular one, wind speed or whatever it is—icing around power stations and lines and substations and so on.
The thing where there seems to be less a consistent answer, and the area which we are seeing as an area that we need to consider more, is around combinations of events. So the individual events are covered, we think, broadly, but it is combinations of events—the sea level piece with a wind speed piece, the icing with a sea level piece and so on. Many of these things go together, to do with air pressure and so on, and they tend to get linked. That is the area that we are seeing where there is potentially some risk that needs to be considered more carefully, in terms of how we plan. It is about combinations of risks, but also being realistic about the combinations of risks and not necessarily seeking every kind of edge-of-envelope possibility. What are the realistic combinations of risk we think we face in the future? We are now looking at how we would seek to identify those and what groups in the UK are best placed to do that, and we have not completed that yet.
Viscount Ridley: What I am concerned about is that this could be a very small effect—this combination effect, this extra effect, this marginal difference that climate change will make—because, presumably, ice storms and sea level rise combine anyway, as it were. The sea level has been rising for hundreds of years, so we are already seeing small impacts of that, and so on. In weather like we have this week, we could have an ice storm because it is
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cold but very windy, but it is not quite cold enough to be snow, so it could be rain falling on ice and that kind of thing. What is the extra? The extra could be quite small, because we could move through that phase into a phase where ice storms are less likely or something like that.
Professor Anderson: It could be quite small, and it could be very large. Again, we cannot give you much information on that either way, partly because the science is very unclear about those particular extreme events, but I would say probably the largest thing is that we have no idea how the global community is going to respond to climate change. Currently, it is doing nothing in terms of reducing its emissions, which are going up at a three times faster rate of growth than during the 1990s. So we do not know how much energy there will be in the system going forward, because we do not know what the greenhouse gas concentration in the atmosphere will be. We have no idea how we will respond to that challenge, let alone the idea that there are huge difficulties in trying to make accurate predictions of weather. We can be fairly robust on climate, but the difference between climate and weather, as I think most of us understand, is important to understand.
Most of you are probably familiar with this, but if you think about splitting the grid into two parts, you have the National Grid, the big transmission stuff, the high voltage part of the system, and you have the district network operators, the DNOs, the lower voltage part of the system. My impression is that National Grid are more up to speed with the sorts of impacts that they may well see in the short to medium term than the DNOs, the district network operators, are. It would be fair to say you should question them as to whether they would agree with that or not. Most of the outages we see are not caused by the National Grid going down; they are caused by more localised effects. I think 35% of all outages, short-term outages, are from lightning strikes. Again, we are poor at predicting what the impact of lightning will be going forward. I am not trying to make great claims as to what we can do, but what we know is there is more energy system going forward and that these extreme events will likely play out more regularly.
The other point to bear in mind, and I am having to rely on my colleagues for this, is that, as I said before, the small increase in wind speed you referred to has a much larger impact in terms of damage, because there is this cube law associated with it. We have to understand that we may describe it as a small increase in wind speed, but we have to be fair about that and use the language then that would imply a very large impact in damage, or it could do, depending on exactly what those numbers were. But we have to draw that important distinction between those two.
The other thing about whether it is resilient enough or not comes back to the comment about systems. We have an electricity system and we have a whole set of nested systems. At the moment, electricity provides us with our lighting and numerous other things. It does not provide us with much transport. It provides us with some trains and trams and some buses, I suppose. But going forward, if more things are on the grid, you might make the argument that we have a whole suite of nested systems that are now reliant on electricity, so the level of resilience might have to be much higher.
Viscount Ridley: But that is the point about climate policy impacting.
Professor Anderson: It is not just climate policy. Without climate policy, we are putting more on the grid. I notice one or two laptops around here—previously they would have been pens and paper. So we are already reliant on a whole host of infrastructures that we would not
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have been using 10 or 15 years ago. ICT is very important to us now, so I would argue that, without climate policy, the issue of resilience is changing anyway because we are using electricity for a whole suite of things we were not using it for before. I would argue, on top of that, that climate policy will add additional things to those anyway.
Q132 Lord Dixon-Smith: I am becoming slightly puzzled. Of course one needs to be aware of the possibility of the extremes, but I live by the weather in my other career, when I am not in this place, and I have done that all my life. I am bound to say to those who think that climate is not changing that the climate is dramatically different from anything that I grew up in. I used to skate every winter. I have not skated for years.
But going the other way, I did not understand why you were so concerned about a possible air-conditioning power demand surge, because I spent 18 months in Malaya—God help me, over 50 years ago now—and I have to say that nobody out there at that time had heard of air-conditioning, or virtually nobody. It was not an issue and, frankly, we lived very, very comfortably. We did have a record low temperature while I was there. It was only 59°F. I cannot put that instinctively into centigrade degrees. But the adaptability of people, in my book, will mean that there is not anything like the demand for air-conditioning that you are describing. It was you, Professor Anderson, right at the beginning. I listen to that and, I am sorry, when you question one bit—
The Chairman: Lord Dixon-Smith, we will hear from Professor Anderson. Thank you.
Professor Anderson: In many respects, I would agree with you. It is not that we need air-conditioning; it is that we are already normalising to it. I have colleagues now, in a 1960s building, who have bought portable air-conditioning units for their offices. They have been working in those offices for years and the climate has not changed that dramatically but they still have to move to AC units.
The problem is that we normalise new types of practices and behaviours. I lived in the north-east for a while and I can tell you that people in the north-east were wearing T-shirts, where people from London would have been wearing coats in that weather. We normalise to certain behaviours. I am not saying we have to go down that particular route. We could retrofit our houses to help as well, no doubt, and we can learn to put coats and jumpers on. We can do all those things, but there is a real risk that the grid has to consider, which is that people will, unless there is some legislation to stop it, likely start to move towards air-conditioning loads. We already start to see it in some of the more prestige properties that are being built. They are putting air-conditioning units in there. You can already buy retrofit air-conditioning units.
A few years ago, people would have said that you would never heat your garden to have a barbecue outside in winter, but we now heat our gardens. There are a whole suite of practices that we put in place that lock in these types of behaviours and normalise them. I am with you. I think there are many things that we can do, and that is one of the things we are looking at in the project, to try to bring down what could be the air-conditioning load. Are there other things we can do? Are there practices we can adopt? Are there forms of legislation that could help to reduce the uptake of air-conditioning load? Are there retrofit opportunities for the houses we live in? Nevertheless, in the absence of those things, there is quite a lot of evidence in other countries that we’ll see an uptake in air-conditioning load, and we are already seeing that in the UK. We already see the bottom of the curve. I am with
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you. I hope the curve suddenly drops off, and I am sure National Grid do as well. Nevertheless, in the absence of other policies to put that in place, it is unlikely we will not see an ongoing increase in air-conditioning load. It will not be like Malaya in the 1950s; it will be more like Dubai now.
Q133 Lord Rees of Ludlow: I want to follow up on the impact of climate policy. The first question is: do you think the policies we have are ever likely to achieve the targets by 2050? Secondly, clearly, there are going to be impacts on the nature of the grid and its resilience from the greater dependence on renewables. I wonder if Dr Clarke would like to start on that.
Dr Clarke: I will take those in reverse order and start with the impact of renewables on the grid. It is not just renewables; it is the broader spectrum of what technologies we implement. To some extent, going back to your last question around the consumer end of this and what people expect, the reality is that we always talk about security, affordability and sustainability, but we may as well also talk about the trilemma issue of technology, consumers and then policy and business models, and how those three things fit together. The consequence of that is—probably the greatest certainty—that consumers, and I am going to use a very bad phrase, will demand stuff in the future. We do not know what it will be, and that is the uncertain bit, but there will be changes. People will want new technology; they will want different approaches to how they engage with it. That can be supported or destroyed by policy, as we all know, and the easy example I always use is, right now we have about 220 significant power stations on the grid, bigger than 5 megawatts—220, that is it. We have 575,000 solar installations of less than 4 kilowatts. Five years ago, eight years ago, they did not exist. Things change. That was driven by policy; that was the take-up. Now the cost of that is coming down and policy is stepping away from it, for good reason. I stress that because it can change and the grid can change in its nature quite quickly. We have never seen that before in this country, and it is happening. The point is that consumers can demand things. Whether it makes rational sense or not, it can happen.
You ask how we see these things changing. From an electricity point of view, the two issues primarily to be considered are vehicles and how electric charging may work on vehicles. But frankly, it is a tractable problem, because, in the main, you have the ability to charge your vehicle overnight. Heat is the issue. If we move towards electric heating, in general terms, when is everyone going to want to turn the heating on? Five or six o’clock on a Friday night in winter, and they will all come on simultaneously if we use conventional heating solutions. So you now say the only way of managing that, if you are in an electric heating world, is to look at the building fabric—you have to look at how the consumer uses their heating and how the actual heating system works. So, suddenly, it is technology, it is incentives to make people retrofit their buildings, it is the business model in terms of how they buy the electricity and off whom. It is not a trivial problem and I think it is impossible to separate the technology, the policy, and the consumer piece.
Lord Dixon-Smith: Can I follow up that last just slightly? The late Battersea Power Station used to heat most of Battersea and half of Chelsea, and not least of our problems is that we insist on putting our power stations miles away from anywhere, so that half the energy they produce is wasted—waste heat. A radical change in that, just from a planning perspective, could in fact do a very great deal to sort that out.
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Dr Clarke: The reality of what you just said is absolutely correct. The challenge is building an economic power station at a scale and with the infrastructure that can be installed in a near urban location. It does not have to be in Battersea—10 miles away would be adequate. You can pipe water that far, hot, without a problem. I agree with you, and that is why it is important to look at the system and how we utilise that waste heat.
Today, the vast majority of our power stations with heat generation attached, spare heat, are very large installations, which we have had to place out of town for infrastructure reasons to do with fuel supply and to do with emissions. We have been looking recently at where you could site power stations in the future. If you accept you are going to a slightly smaller scale, then the benefit of the scale is you probably need less cooling water. That is one of the critical drivers, cooling water, on where you site a significant power station.
What we are starting to see is, certainly in England, 30 to 50 sites where you could put a power station, either thermal or small nuclear, potentially. You could put that within an acceptable distance of an urban conurbation to be able to use the waste heat, and most of those are brownfield sites. But you are tremendously restricted by a whole range of issues, not just the obvious ones of logistics of getting fuel in, of getting cooling water, but air corridors over power stations are restrained for obvious reasons, for security and so on. There are all sorts of issues, but we are seeing 30 to 50 sites where we think you could start to place either a small thermal or a small nuclear plant in the future, when you could use the waste heat. I absolutely agree with you, using waste heat is crucial in keeping the cost acceptable at a national level for the infrastructure in the future.
Q134 Lord Rees of Ludlow: It is clear that any investment decision we make now will have an impact extending to 2050 and beyond and I would like to ask, again perhaps Dr Clarke, who mentioned CCS, whether you think we can ever realistically reach the 2050 targets without CCS? Given that, do you really think CCS will ever be scalable?
Dr Clarke: As I said, we carry out quite detailed analysis around potential designs for the UK energy system out into the future, in the context of meeting energy sustainability targets. The number one message that we would take out of that is—this is across power, heat, transport, fully integrated—if you elect not to use CCS, and therefore essentially do not use fossil fuels out to 2050 in terms of power generation, the first question is: can you still meet climate change targets? Our analysis says you can. So you can do without fossil fuels, but only at a cost. The cost is of the order of 1% or more of GDP. That one decision is the single biggest decision you make about the UK energy system in terms of the cost of the system and that gets passed on to consumers.
So the question: is CCS important? To my mind, it is critical in keeping costs down. How do you operate without it? The answer is, you have to rely very heavily on nuclear and you have to rely very heavily on offshore renewables, which is doable, but it brings cost penalties. How do you prove off CCS? How do you prepare yourself for this world of 2050 and test it? The answer is, you look at what is going on around the world, you utilise that expertise to a degree, but you need to prove it in the context of the UK engineering systems, and the regulatory systems in the UK, and the financial desire to invest in the UK from major investors. All of that says you need to continue with the current commercialisation projects that DECC are doing, which are absolutely critical, and you need to get probably between two and five full-scale plants up and running by the mid-2020s, certainly by 2030, so that the investment community can see the viability or not of those systems. But that is crucial.
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Professor Anderson: I would agree with a lot of what David said, but I would probably want to come back a little bit on the CCS issue. First, we are often vague in our discussion around climate change, a sort of nebulous framing of it. We have an 80% target for 2050. What I am saying is that this target has almost nothing to do with climate change. We have said this repeatedly for a long time. It is the cumulative emissions that matter. What happens in 2050 is an irrelevance. It is what happens in the pathway up to 2050. According to the IPCC carbon budgets, we have left it so late that it is what happens between now and 2030. So we are talking about a much tighter timeframe and it must be related to the carbon budget. So if we follow the UK policy at the moment—and if the rest of the world is following suit, which, as I say, it is not anyway—we would not be aiming for 2°C, we would be aiming for something that the CCC and many others have defined as extremely dangerous. Certainly, if you live in the southern hemisphere on a low-lying island, you would see it like that.
We have to be very clear about what we are talking about in terms of the climate change issues. When it comes to issues of affordability, we also have to be careful to say we are not interested in the price of energy, despite the fact that we all talk about that. We are interested in the price of services. No one cares about the price of energy. What you care about is the price of light, or listening to your CD, or hoovering, or travelling a mile. That is about the combination of efficiency, both technical and behavioural efficiency, and the price of energy, and we have to bear that in mind. If we are going to become twice as efficient, which is fairly easy to do in our inefficient world, then you can double the price of energy and the price of services remains the same. We have to move away from the idea where the price of energy is important or is not important.
For the CHP issue, combined heat and power, I am completely in agreement with David and this is really important from the grid perspective. There has been so much discussion around heat pumps, which require a lot of energy, electrical energy, to provide heating and we are wasting more than half. For most power stations, nearly 60% to 70% of the energy goes up as waste heat. We cannot use all of that for various thermodynamic reasons. Nevertheless, we could use a significant proportion of it. If we are going to go ahead with new nuclear stations, we should be seriously considering that.
One of my PhDs, who has now submitted and passed his PhD, looked in some detail at nuclear CHP. He was looking at Hartlepool, because there are many houses around Hartlepool, where they have a nuclear power station. If they go ahead with another one, those houses could be provided with heating at virtually no reduction of efficiency from the nuclear plant. Now, the problem with that is we have economists, and economists in this country like to have high discount rates. If you have a high discount rate, you will build nothing that requires money to be spent on significant capital upfront. Until you change the economists and the discount rate they apply, you will not build things that have a high capital cost, unless it is driven by some other government policies around that.
The Chairman: It is good to deflect the blame in a direction that is—
Professor Anderson: Finally, I come back to the CCS issue. Carbon capture and storage is not a low-carbon option. Let us be clear about this, as people often think of it as zero carbon, yet it has high emissions. These are still quite theoretical assessments because we do not have that many operating plants to assess, but there are a few papers out there saying if CCS is done well they are going to be over 80 grams of carbon dioxide per kilowatt hour, which is five to 10 times greater than that from nuclear or renewables. So it is still a high-carbon
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energy source, even with a successful CCS, and that is taken across the life cycle of a plant—not just the plant itself, but the emissions across the whole fossil fuel chain, and that is running it fairly efficiently, or as efficiently as we can imagine we can do. So it is still relatively high carbon. You then have to ask the question, going back to quantifying our concern around climate change: does that fit in the carbon budgets? It fits in our domestic budgets for an 80% target. As I say, that is not related to climate change. It does not fit within any decent budgets for 2°C for the UK. We can be quite clear quantitatively about this whether it fits or not.
Q135 Baroness Sharp of Guildford: Let me carry this forward a little bit. You have talked quite a lot about the use of low-carbon electricity for heating and transport, and in particular there has been a lot of talk about heat pumps on the one hand and electrifying the transport system on the other. What sort of timeframe is it envisaged that electric vehicles and heat pumps will be taken up in? Secondly, will the electrification of the whole energy system decrease the resilience by reducing diversity? It is almost bound to, from the discussion we have been having. I think it is fairly clear that this is so.
Dr Clarke: You ask, “Would widespread electrification decrease resilience?” I am sorry to give you the engineering answer, but it depends how we implement it. I know this is a pretty trite answer, but you would design it so that it did not. That is the crux point; you would have to set out to design it so that it did not. That implies you have an approach to designing the system that is controlled quite closely. If you were designing for very widespread electrification, you would almost certainly be looking at local units, if you see what I mean. You would be breaking it up in that sense to give you the resilience. There are ways and means of doing it, but it implies careful thought and it implies there is a group tasked with delivering that system design. This is the kind of thing the IET have been proposing about system architect for the UK and so on. It implies that, and I think it is correct that you need that kind of thought in terms of the design standards.
Baroness Sharp of Guildford: Can I just break in? Does the development of microgeneration make this whole question of design much more difficult?
Dr Clarke: Yes, but again it is a fine engineering challenge, if you see what I mean. Yes, it makes it more difficult. Perhaps I should say, to be more precise, it makes it different. Does it make it more difficult? It is debateable. The real issue to some extent goes to the first part of your question about the rate of take-up and rollout of heat pumps or vehicles. It will be very nice to look at the UK or even England or one of the other nations and say, on average, we would see rollout of electric vehicles to the tune of a few per cent of the car population by 2025. The reality of what you will probably find is that it is very segmented geographically. For the sake of argument—I am not picking this for any particular reason—you may find that Battersea, going back to an earlier comment, becomes heavily electrified in terms of vehicles. That brings all sorts of local issues around the local distribution systems in that area, but nationally you would not even notice it, clearly. I think that is the challenge, the whole point around microgeneration and take-up of some of these new technologies. It brings local issues. Where I live on the end of a relatively small gridline, a very few solar installations can push the voltage up in summer and it causes a problem on the local transformer.
Baroness Sharp of Guildford: I was also going to ask you about the air-conditioning load. Surely the development of solar installations will have some effect on this, will it not?
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Dr Clarke: It could do. I say that carefully. It could do. The reality is that solar works when the sun shines. If you want the air-conditioning at the same time, which sounds sensible and logical, then broadly speaking you may argue that the two balance out. If the sun turns off for 30 seconds with a cloud, you have a blip in the system, which has to be managed. The challenge you quickly come to is: how do you manage storage and those short-duration effects? Yes. It is all about the system design, I am afraid, at the end of the day.
Q136 Lord Winston: We are running out of time, unfortunately, but perhaps, succinctly, you would like to just tell us a little bit about the impact of the smart grid and smart meters and what the barriers are to their implementation. Also, if somebody could give us a word on cybersecurity and whether you see that as a problem in the future, that would be helpful as well.
Dr Clarke: I can comment on cybersecurity. The answer is yes. There is quite a serious issue there that needs early consideration. There have been a number of challenges, not just around security but around personal privacy and data, and that is being managed through the smart meter programme at the moment. Clearly, everyone is worried about the ability from a cybersecurity viewpoint for tampering with the electricity system. Equally important, though, is tampering with the demand side, because it is very easy, and I know a number of people are worried about the concept of the ability for somebody to change the charging codes, for instance, in electric vehicles, such that they do not all turn themselves on at night, but they do all turn themselves on at 5 o’clock on a Friday. It could lead to quite a big cascade failure in local areas, so it is a key issue, absolutely.
Lord Winston: Is there a problem about, for example, having a firewall between smart meters and the grid? Does that help? Would that help?
Dr Clarke: I would put it in the class of it is a manageable problem in the same way as we manage cybersecurity in other areas, but it needs early consideration, and it is not just the security issue. It is the personal data privacy issue as well, which just needs to be thought through very carefully, and the Smart Metering Group and National Grid are working on this.
Lord Winston: Finally, if you would—and if that is all right, Lord Chairman—can you give us some estimate about the effect on the resilience of our electrical suppliers? Is that possible, do you think, or do you think that is just another example—
Dr Clarke: I do not have any particular data on it.
Professor Anderson: Again, we still have another two years to go on the project, but from some of the early work on smart meters we know that, again, it depends very much on how they are implemented and how the public respond to them. Remember, these are something the public can be dynamically engaged with, and that is always a challenge to predict. Smart meters may well give us an ability to have greater resilience in the grid.
Also, if you think about that from an intermittency point of view, if we are going to have more renewables on the grid—which we certainly will do in the short term and, from a climate perspective, we should do in the longer term—then it may well be that smart metering techniques allow you to look at the weather for the next six hours, two days and so forth and, via smart metering, start to allow the demand to follow supply. We always have this idea that supply follows demand, but with smart meters and intermittent supply you can then start—at least for some areas of demand—to adjust the demand in accordance with the intermittent supply, if it is as intermittent as some people suggest. That, in a sense, gives
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you a greater level of resilience, but also bear in mind that smart meters themselves do not save you any energy particularly. They might save you a little bit. They allow you to run your system, if they are appropriately put in place, much more efficiently, make more use of your capital stock and reduce your operating costs and so forth. They do not themselves solve climate change, but they allow you to look at a much more complex system and try to run it in a more efficient manner.
At the moment, the meters we are putting in place, where you effectively just get a little dial that tells you how much energy you have used, these are just less dumb meters. They are not really smart meters. Smart meters are where you start to get some correspondence between your refrigerator and the supply network.
I will not go into cyber issues, but there are lots of protocols you could put in place to try to resolve those, but they are an issue for people who are experts in that area, which I do not think any of us particularly is.
The other thing I would say is just to re-emphasise that smart meters are not just a technical issue. It is very much a personal issue. We will get engaged in the same way that solar power is something we have got engaged with. It changes how consumers use energy. Similarly, smart meters may well do that, so we have to be very careful when we design these things to take account that there will be lots more Rumsfeldian unknowns out there.
The Chairman: We have pretty well run out of time. In fact, we have overrun our time, but I know that Lord Ridley and Lord Peston both want to ask questions. Lord Ridley.
Viscount Ridley: Very quickly.
The Chairman: Very quickly. Ten seconds.
Q137 Viscount Ridley: What I am hearing this morning very clearly is that electrification and renewables policies are a threat to resilience in themselves, or rather, if they are not to be, then they are a threat to affordability. In other words, we can buy resilience in this newer world, but only at a cost.
Matthew Bell: To draw that together with some of the discussions around the links to policy from Lord Rees and smart meters and things, the policy framework is such that we have the 2050 target for 80%. We have set out, and Parliament and Government have agreed, out to 2027 what needs to be done. There is still a lot of policy that has to be developed in order to meet those targets.
We have not touched on the affordability and the cost side of this, but what is clear is that there is a lower cost way of doing it and there are more expensive ways of doing it. That was the example of CCS and that was the example of other things. Right now we do not know what technology mix will be the best technology mix and what demand-side response will be the best demand-side response to get us to where we need to be, and that is why it is sensible to be looking at and trialling and piloting a range of different technologies and a range of different measures. We will see which ones emerge as the most cost-effective ones, but we are, from the Committee’s point of view, trying to maintain ourselves on that least-cost, most cost-effective path and see which ones come out.
In terms of specifically the costs of the intermittency—I appreciate lots of us have said this; it is not that much help right now—we are doing a very detailed piece of work right now on the cost of intermittency and trying to understand what it is. We did a piece of work, which
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is public so we can certainly share it, in about 2011 that looked at the cost of intermittency, and that estimated that it would add about 1p per kilowatt hour to build the more resilient network that was needed, with the evidence that we had at that point in time. To give you a sense of 1p per kilowatt hour,17 we are currently delivering energy to households at about 15p per kilowatt hour. That gives you an order of magnitude feel, but there is lots of uncertainty, as we have emphasised, around all these things.
Professor Anderson: You can just quickly turn that on its head. I think you can make an argument that renewables improve your resilience and affordability because they reduce your susceptibility to price volatility of fossil fuels. As more demand comes on the fossil fuel market internationally from China and other parts of the world, the price of fossil fuels will vary significantly. The price of the wind will remain roughly the same. It does not cost much to blow.
Viscount Ridley: The cost of fossil fuels has gone down in price—
Professor Anderson: Yes, but I said volatility, which goes up and down. The price of fossil fuels goes up and down, and volatility is itself an issue if you are trying to spend money on capital. I think you could argue, particularly going forward, that there are benefits from an affordability perspective, and if you look at the capital cost of some of the renewable options now, if you apply very high market discount rates, they do not work out so well. If you apply more social discount rates such as they use in the Green Book, then a lot of the renewables now are on a par with some of the fossil fuels, and you do not have to pay for the fuel afterwards.
The Chairman: With integration costs?
Professor Anderson: Even if you include the integration costs, yes.
Q138 Lord Peston: Just briefly I want to get the context right as we come to a conclusion. Following from Lord Winston’s question on smart meters, which are a good idea but have a downside, what worries me about all our discussion, as Professor Anderson pointed out, is that we have in front of us more computing power than John von Neumann or Alan Turing ever dreamed of when they were winning the war, or rather Alan was, but all of these great technical advances have a downside. You cannot hack into an e-mail if you do not have e-mails. You cannot ruin people’s calculations if they are not able to do incredibly advanced calculations. Do you agree that we must place all this in the context that all the advances—the plus side—clearly must always have a minus side?
Matthew Bell: I agree that there is no free lunch and that there is always a cost associated with these things. In a policy context, the question that was before us today in a climate change context is: what does the world look like without doing anything, what does the world look like with doing something, and what are the costs and benefits of acting compared to not acting?
Dr Clarke: If I can just say, from the point of view of getting to 2050, I was trying to think of it perhaps to some extent in this way: power, heat and transport, cars. We change cars about
17 See Committee on Climate Change, 2001, “Renewable Energy Review” page 60 at http://archive.theccc.org.uk/aws/Renewables%20Review/The%20renewable%20energy%20review_Printout.pdf ; and the associated technical annexes at http://www.theccc.org.uk/publication/the-renewable-energy-review/.
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every eight years, on average, so you have three goes at that between now and 2050, maybe four. We change boilers in houses about every 15 years. You have two goes. That is it. Power stations last 25 to 50 years, so you have one go, and that go is now. When you look at those, the first two, cars and boilers, basically it is a consumer decision, and the technology that goes into your house—anybody’s house—is pretty much driven by regulatory standards and legislation in terms of its efficiency and European standards and so on. The power stations to some extent are driven by regulation and standards and so on, but a lot of it is driven by government policy and what incentives there are to invest. If you had to look at those three, then I think there is an important piece that says the consumer is absolutely critical on two out of three. Government is crucial on all of them, but particularly on the power station one. If you look to getting to 2050, we have about a 10-year window from now to test out whatever options we think we need, and there are options. There is not one size that fits all. They all come with downsides and penalties—all of them, other than business as usual—so now is the time to focus, I think, on the options, to test the options, and then we have to go for a rollout.
The Chairman: I had better close the session now because we have overrun. We are most grateful to you. We have not, I suspect, had a total meeting of minds on every subject, but we have agreed, I think, there is no such thing as a free lunch, we have agreed that we need to test the options and that the issues are what we do not understand as much as what we do understand. Thank you very much. If we have been at times scratchy, I apologise, but that is because you have stimulated a lively discussion. Thank you very much.
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Confederation of UK Coal Producers (CoalPro) – Written evidence (REI0021) ‘Managing the UK’s electricity system – can we keep the lights on?’ CoalPro’s Mission:
TO promote the UK coal industry, provide the most secure source of energy for the nation whilst accepting environmental responsibility.
TO promote best working practices throughout the industry to ensure the Health, Safety and Welfare of all.
TO work with the UK Government, the devolved administrations, Mineral Planning Authorities, Local Authorities and other agencies to access coal reserves for the benefit of local communities and the nation.
TO promote the industry at European level and with the world mining community to secure a long-term role for coal in energy supply.
Key recommendations to the House of Lords Science and Technology Select Committee inquiry on Resilience of Electricity Infrastructure Introduction The stability, integrity, diversity and maintenance of today’s UK electricity infrastructure is increasingly at risk due to a high unilateral Carbon Price Floor (also known as Carbon Price Support), which was introduced by the Government in 2013. CoalPro maintains that reduced carbon taxes and abandoning the Carbon Price Floor can strengthen UK security and resilience of electricity supply and infrastructure, strengthen diversity, boost affordability and provide a bridge to future Carbon Capture and Storage (CCS).
1) Abolish the Carbon Price Floor (Carbon Price Support) Urgent and serious consideration should be given to abolishing the Carbon Price Floor (CPF) post 2016. The original purpose (as promoted) of the CPF was to help stimulate investment in low carbon technologies such as carbon capture and storage (CCS); however, the capped CPF and resultant wide divergence from EU carbon prices will drive early premature closure of existing coal plant, risk UK energy security and electricity infrastructure resilience, cause carbon leakage and drive up power prices without encouraging investment in low carbon technology or impacting global emission levels. The CPF is merely an income stream for Treasury with significant side effects.
2) Existing coal plants should be able to secure viable Capacity Payments The design and implementation of the Capacity Market should provide existing coal plant with a realistic expectation of recovering investment. It is essential to ensure continued reliable and flexible performance whilst meeting the costs of adherence to environmental
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legislation and of the Carbon Price Floor. Emission Limit Values (ELVs) under the Industrial Emissions Directive (IED) should be grandfathered until 2030 with no further tightening of emission limits policies to drive forward the development of CCS
3) New coal CCS demonstration plants must be prioritised New coal with CCS should be accelerated and expanded through the urgent development of two demonstration plants under the current CCS competition.
4) Contracts for Difference for new coal with CCS projects A clear ambition should be set out to use EMR and Contracts for Differences (CfDs) to support coal CCS projects outside the current competition so as to advance the commercialisation of the technology. The target should be for these projects to commence operation before the end of this decade.
5) C02 transportation networks must be prioritised The development of CO2 transport and storage networks should be supported, which will enable the cost-effective deployment of coal CCS in the UK. Delivering CCS commercialisation and a CCS critical mass A CCS Commercialisation Programme should be established, that sets out a clear ambition to deploy a minimum critical mass of 10 GW of CCS by 2030. A minimum CCS volume goal would allow the technology to be commercialised, whilst permitting coal CCS to secure a larger proportion of the electricity market, if it proves cost- competitive with other low-carbon generation sources. What will this deliver?
Effective transition and bridge from unabated coal to coal with CCS
Retention of 10,000 direct jobs and the creation of highly skilled roles at new CCS plant, in coal mining and throughout the supply chain
Maintenance of access to the UK’s vast recoverable coal resource
Security and greater affordability of electricity supply for the UK
A hedge against increasing gas prices, and therefore reduced risk of higher consumer
bills and overdependence on imported gas
CCS transport and storage networks as the basis for power and industry CCS networks in industrial regions
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Potential for the UK to become a world leader in the development and deployment of CCS; if CCS for coal is not available then there is no hope of global emissions being reduced in the next 20 years
A mixed energy portfolio with the UK not over-dependent on any one fuel for the
generation of electricity
Reduction in pressures which lead to carbon leakage where UK industry relocates to neighbouring states with lower carbon prices, particularly the EU
Prevents a high carbon lock-in for the medium to long term with the UK overdependent on unabated CCGT gas plant
What are the consequences of not doing this? The UK is in a unique position to develop CCS technology for coal, with its resources of technological competence, finance, manufacturing expertise, natural storage advantages in the North Sea and an indigenous coal mining and coal power industry committed to powering the UK long term. The UK has a significant coal resource which will not be accessed unless actions are taken within the coal generation market. There is a real concern that existing coal stations will have closed before new coal with CCS technology can be established, with the consequence that:
Indigenous coal production will have disappeared together with the UK’s well established coal supply infrastructure
Loss of over 10,000 direct jobs and the skills associated with these roles
A lost opportunity to develop a world class coal CCS industry based on UK coal
Reduced coal generating capacity by 18GW between 2016 and 2023 as existing unabated coal plant is forced offline due to high and rising taxation under the proposed carbon price floor trajectory
A sudden significant loss of income for the Treasury as coal plant is closed earlier
than planned or anticipated
Security of supply diminished as the UK becomes overdependent on imported gas for electricity generation
Increased costs for consumers
How reduced carbon taxes and abandoning the Carbon Price Floor can strengthen UK security of energy supply, strengthen diversity, boost affordability and provide a bridge to Carbon Capture and Storage (CCS)
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Introduction Coal fired plant continues to play a crucial role in the UK electricity generation portfolio, providing around 40% of electricity generated across Great Britain in 2013. This contribution from our existing coal generation fleet, and the associated supply industry and infrastructure, is absolutely essential in providing secure, flexible, and affordable energy supplies to the UK’s households and businesses. In particular, retaining coal as part of the UK’s energy mix will provide a hedge against future volatility in the gas market which would otherwise be passed directly on to the consumer. It is vital that the remaining lives of these coal stations are managed effectively and utilised optimally to enable maximum contribution to the UK’s power requirements over the next decade, through the transition to the future low carbon generation portfolio. This will also ensure continuity and progression in the skills, capabilities and resources required to support the development of clean coal with carbon capture and storage (CCS) as part of the future generation fleet. The right policy signals are needed from Government for building much needed investor confidence in the coal supply chain, including indigenous mining, ports and transportation infrastructure. With the support of an ambitious, Government led CCS strategy, coal has the potential to provide secure, affordable low carbon energy through to 2030 and beyond. The Committee on Climate Change in its Fourth Carbon budget assumes a significant role for CCS for coal and gas in the UK’s 2030 energy mix18. The scale of coal’s current contribution and its future potential cannot be underestimated, yet, and in contrast to most of our main industrial competitor nations, the future of the industry is under serious threat from an energy policy framework which is driving premature closure of the current fleet. At the same time, the construction of new high efficiency CCS-ready coal plant is effectively prohibited. The UK has also failed so far to deliver the momentum required to seize the opportunity of CCS technology. This is despite the significant progress on deploying large-scale CCS projects being made in other countries and the strong national advantages that makes the UK one of the best places to deploy the technology. Fossil fuels will continue to play a dominant role in the world’s economy for the foreseeable future. Both the International Energy Agency (IEA) and the Intergovernmental Panel on Climate Change (IPCC) acknowledge that CCS is a key global carbon emissions mitigation technology. Without CCS our aspiration to limit a rise in global temperatures to 2 degrees will be much more difficult and 40% more costly19. There is considerable evidence that inclusion of CCS within the future decarbonised energy portfolio is consistent with the least cost pathway to decarbonisation and will result in lower electricity prices than in a non-CCS future energy scenario.
18 http://www.theccc.org.uk/publication/the-fourth-carbon-budget-reducing-emissions-through-the-2020s-2/. 19 IEA – Technology roadmap: Carbon capture and storage.
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The UK has the opportunity to bid for a significant stake in this global market, ensuring that the UK becomes a world leader and champion of coal fired CCS technology. However, action is required now as a matter of urgency. The Government has to clearly define its ambitions for CCS delivery. The Electricity Market Reform (EMR) programme contains 2030 scenarios ranging from no additional CCS projects (beyond the current two projects in the current CCS competition) to 12 GW capacity. Within the literature, 10 GW by 2030 has been suggested as a conservative level of deployment, with a more ambitious, but achievable target of 15GW set out by the Committee on Climate Change20, and 20GW suggested by the CCSA21 and endorsed by the TUC. Given the long lead times, the Government must provide much greater clarity in its vision for clean coal with CCS. The Climate Change Committee22 has argued that the Government should establish a CCS Commercialisation Programme that sets out a clear ambition to deploy a minimum of 10 GW of CCS by 2030 in order to commercialise the technology and provide the UK with a portfolio of low carbon technologies that can deliver substantial emission reductions beyond 2030. Setting a minimum CCS volume would allow the technology to be commercialised whilst permitting coal CCS to secure a larger proportion of the electricity market if it proves cost-competitive with other low-carbon generation sources. Adoption of the policies above would give the UK:
Effective transition from unabated coal to coal CCS Retention of 10,000 direct jobs and the creation of highly skilled roles at new CCS
plant, in coal mining and throughout the supply chain Security and greater affordability of electricity supply for the UK A hedge against increasing gas prices, and therefore reduced risk of higher consumer
bills CCS transport and storage networks as the basis for power and industry CCS
networks in industrial regions Potential for the UK to become a world leader in the development and deployment
of CCS; if CCS for coal is not available then there is no hope of global emissions being reduced in the next 20 years.
Conclusion In conclusion, the United Kingdom needs an energy strategy which delivers long term, competitive and secure energy whilst meeting carbon reduction targets. Relative energy economics will change over time, and maintaining a balanced electricity generation portfolio is crucial to limiting exposure to changes in future commodity prices and technology costs.
20 Committee on Climate Change, Next steps on Electricity Market Reform – securing the benefits of low-carbon investment, May 2013. 21 CCSA Response to Energy and Climate Change Committee Inquiry into Carbon Capture and Storage, Sept 2013. 22 http://www.theccc.org.uk/wp-content/uploads/2013/05/1720_EMR_report_web.pdf.
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Coal with CCS has the potential to play a key role in that strategy and a transitional plan and ‘bridge’ from unabated coal today and into the mid 2020s to coal fired CCS plant must be established as a matter of urgency to ensure that this potential is realised. The abolition of the carbon price floor to deliver this bridging policy and boost energy security and electricity infrastructure resilience is therefore key. Background Information and Supporting Analysis for House of Lords Science and Technology Committee Inquiry on Resilience of Electricity Infrastructure Introduction This document provides a view on the current role of coal mining and coal fired generation power in the UK electricity mix, including the role of the UK coal sector in the global economy. It identifies the key priorities and actions the UK Coal Forum requires from Government, in order to ensure the transition from unabated coal through to coal fired CCS. It highlights the potential coal production capability and its benefits to the UK. The UK’s first commercial coal fired power station was built at the end of the nineteenth century. Since then the UK has used coal as part of its energy mix which continues to date. UK coal plant operators have successfully worked with environmental regulators to implement environmental permit conditions, resulting in a steady reduction of emissions. However, they now face tough decisions on whether to invest further, in light of uncertain environmental legislation and unilateral UK policy on carbon dioxide emissions. During the transition to coal CCS, it will be crucial to ensure that the highly skilled workforce employed within coal mining (deep and surface), equipment manufacturing, rail and ports, are retained, so that new plant can call on skilled staff to operate and maintain sites. The continuation of current coal plant, and transitioning to coal CCS, would support many areas of the UK economy, directly and indirectly. Coal mining in the UK Coal production in the UK in 2012 was just over 17 million tonnes against a total coal demand of 64 million tonnes, with imports making up the difference. The biggest market is that for power generation at around 55 million tonnes which provides the main market for UK coal operators. Therefore it can be seen that UK coal producers and infrastructure operators are inextricably linked to policy decisions made within the electricity market sector. Table 1 – UK Coal Market Breakdown 2012
Supply Million tonnes Consumption Million tonnes
UK produced 17.1 Electricity 55.0 Imported 44.8 Coking 6.1 Stock Change 3.0 Industry 1.9 Domestic /other 1.4 Exports 0.5
Total 64.9 Total 64.9
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Source: DECC Energy Statistics tables 2.5, 2.6 Despite importing the majority of its coal, the UK does have significant coal reserves. A 2013 reserve assessment published by the Coal Authority is shown below: Table 2 - UK Reserves of Coal
(Million tonnes) Under license Identified prospects Total
Deep Mines 1,675 2,010 3,685 Surface Mines 115 775 890
Total 1,790 2,785 4,575
Source: The Coal Authority February 2013 The UK’s reserve base of almost 4.6 billion tonnes would last over 70 years at 2012 demand levels. To access these reserves would require significant investment by UK coal producers, and for this to happen there needs to be a market within the coal generation sector, over the transition period to coal with CCS. Coal mining is an extractive industry which requires investment into new reserves to maintain production levels. The present uncertainty and lack of investment by coal generators is having a knock-on effect on larger surface mines, and in particular on deep mine investment, which by its nature is over a longer term. A prime example is UK COAL’s Harworth Colliery which is currently in a mothballed state. It has access to over 50 million tonnes of accessible reserves, but would need long term sales contracts before investment could be considered. Other markets supplied by UK coal producers are coking, industrial and domestic house coal. The coking market is unique in that coal is part of the steel making process and cannot be substituted by other fuels. Household and industrial coal Whilst the power generation sector is by far the dominant consumer of coal in the UK, coal also continues to provide a critical source of affordable and dependable heat for hundreds of thousands of households across the UK, and is also a vital input to a range of industrial processes. Domestic coal demand for space and water heating is mainly focused in rural areas with limited or no gas mains connection. However, over recent years demand has been supported more widely by the growing usage of coal as a secondary fuel, particularly through the uptake of multi-fuel stoves, and the cost advantage of coal versus alternative energy sources. The domestic coal markets are supplied via a well-established and reliable national retail and distribution network
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There is no definitive measure of UK housecoal consumption, but industry estimates23 indicate a total annual consumption of approximately 900k tonnes, which can be broken down as follows: Table 3 – Estimated Household Market for Coal and Coal-Derived Fuel
Bituminous house coal 500,000 tonnes Anthracite 150,000 tonnes Manufactured Fuel (coal-derived) 200,000 tonnes
Total 850,000 tonnes
The majority of these market requirements are sourced from indigenous production sources. Housecoal is consistently the most affordable choice for off-grid customers versus the main competitor fuels (i.e. electricity, LPG and oil). Coal’s competitive advantage in this regard has remained consistent over recent years across all regions of UK. Figure 1 demonstrates relative costs of heating a typical three bedroomed home across different parts of the UK.
Source: Sutherland Tables July 2013 Figure 1 – Comparative UK Domestic Heating Costs by Fuel With its cost advantage, availability and ease of storage, coal is expected to remain critical to the provision of affordable and secure heat for hundreds of thousands of UK households for the foreseeable future. Industrial demand for coal has reduced over recent decades with the gradual demise of steam generation and space heating applications. However, coal demand for niche markets and specialist industrial applications remains robust. In particular, coal and coke derived
23 Source: Fergusson Group, October 2013.
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from coal are key inputs to metallurgical processes. In 2012 industrial demand for coal in the UK was 1.6m tonnes, whilst coal demand for coking was 6.1m tonnes24 . Contribution of the coal industry to the UK economy Coal is vitally important to the economies of the regions in which it is extracted. Coal is predominantly worked in the regional and rural parts of the UK such as the North of England, and in parts of Scotland and Wales, areas that are susceptible to high and persistent unemployment and other indices of deprivation. Coal is a part of the community in these coalfields, providing employment, skills training and a future for young people. At present there is a definite and substantial need for coal in the UK, significantly in excess of what can be produced from indigenous sources, with every tonne of coal produced in the UK helping our balance of payments, as well as leading to investment into the local economy. Coal related jobs can provide long term, well paid and skilled employment, directly via coal producers and also indirectly through suppliers, support businesses, logistics and users. Using employment multipliers for coal mining produced by the Scottish Government25 we estimate that over 11,000 direct, indirect and induced jobs are reliant on the UK coal mining industry. International coal supply complements indigenous supply and is backed by a highly liquid and diverse international market. A similar number of jobs is associated with the imported coal supply infrastructure at ports, on the railways and at power stations. Coal jobs under threat Options still remain to preserve a critical mass of coal and lead to a cleaner more secure future as part of a balanced energy mix, but without urgent policy changes and indications of future policy support, the opportunity will be gone. Mines, ports and coal handling facilities will shut (or convert to other uses), jobs and skills will be lost, and start-up costs will be too high to recommence in the future. The UK’s coal industry is fighting for its survival, in part because of the lack of clarity on medium term prospects for coal. But UK Government policy must not simply concentrate on the short and the long term for coal. A clear bridge is needed from today, when coal is still generating 40 per cent of our electricity from the reliable workhorses we take for granted, to the CCS-equipped plants of the future. The Carbon Plan published by the Department of Energy and Climate Change (DECC) in December 2011 sets out a long term vision for the reduction of UK CO2 emissions by 80% by 2050. The future energy mix will comprise a number of low carbon power sources, ranging from fossil fuel CCS plant, renewables and nuclear power, and the potential contribution of coal to this mix should not be jeopardised by the lack of a coherent strategy embracing the short, medium and long term.
24 Source: DECC energy statistics, September 2013. 25 http://www.scotland.gov.uk/Topics/Statistics/Browse/Economy/Input-Output/Mulitipliers.
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A transitional plan from unabated coal to coal fired CCS plant must be established as a matter of urgency to ensure delivery of the Carbon Plan and provide the UK with security of supply within the low carbon energy mix required to support the future UK economy. Coal-fired generation in the UK The UK’s current fuel mix is dominated by output from coal fired plant (41% in 2012). As can be seen by the graph below, coal plays a major role in ‘keeping the lights’ on, especially over the winter period.
Source: BMReports Figure 2 - UK Seasonal Generation Mix 2012 Over the past decade changes in global markets have affected the price of gas and coal, resulting in a change to the fuel mix used for electricity generation in the UK. Shale gas developments in the USA have meant that it is now a net fuel exporter. This is one of the factors which has dampened global coal prices making it an even more cost effective fuel to burn than other fossil fuels such as gas and oil. Coal is significantly cheaper to run than gas (around half the fuel cost per kWh of electricity) which places it higher in the merit order and allows it to provide base load generation.
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Source: DUKES 2013 Chapter 5: Electricity Figure 3 – UK Generation by Fuel 2012 The chart above represents the UK’s electricity generation mix for 2012, showing that coal generation makes up 41% of the total, equating to 143 TWh. To put this in perspective, to generate the equivalent TWhs from off-shore wind, 17,500 off shore wind turbines26 would need to be built, and fossil fuel or other back up would still be essential for when the wind is not blowing. The future of coal fired generation in the UK Coal CCS has the potential to contribute to a low carbon and secure energy future, with coal CCS, being deployed efficiently and effectively, competing successfully with other low carbon technologies. On the basis of current policies, with the majority of the current coal fired plant likely to be decommissioned by 2023 or earlier, it is likely that gas fired plant would take the place of coal in supplying baseload electricity with more expensive gas plant and peaking units potentially setting the price of electricity as the marginal supply.
26 Assuming Siemens AG's (ETR:SIE) SWT-3.6-120 turbines 3.6MW turbines are used and that the average load factor for off-shore wind is 25.9% (Average last 5 years taken from DUKES chapter 6).
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Figure 4 – Illustration of Merit Order in Electricity Generation As the graph above demonstrates, once coal plant is decommissioned, the more expensive gas plant will move up the merit order to fill the gap. The increase in gas use and additional running hours of very expensive peaking plant will be passed through to the end consumer. Investment in coal fired CCS has the potential to provide a hedge against future changes in the energy costs due to the volatility of gas prices, sourcing and availability. Recent economic factors have meant that using gas to generate electricity is currently more expensive than coal. Due to the reduced spark spreads some 3 – 4GWof gas fired plant is currently mothballed, with other gas fired plant opting to run in preservation mode. This further reduces the overall gas capacity for the UK. In order to encourage plant to return, the spark spread would need to move from circa £1-2 up to around £12. Environmental regulations impacting coal fired generation The Large Combustion Plant Directive (LCPD) and the Industrial Emissions Directive (IED) are environmental regulations which set Emission Limit Values (ELVs) on large combustion plant. The LCPD requires plant of more than 50MWth to meet ELV limits, to participate in the UK’s National Emissions Reduction Plan (NERP) trading scheme, or to enter into a derogation where plant can run for 20,000 hours up to the 31st December 2015 after which they will need to close. The IED is the combination of several pieces of EU legislation (including the LCPD) which tightens the emission limits set previously. Plants have the option to meet ELV limits, enter the Transitional National Plan (which runs until the 30th June 2020 when plant will then either have to meet the full ELVs or close), operate as a peaking plant with reduced running hours, or enter a derogation where plant can run for up to 17,500 hours until 31st December 2023.
Confederation of UK Coal Producers (CoalPro) – Written evidence (REI0021)
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The LCPD runs from the 1st January 2008 until the 31st December 2015; the IED will then be implemented on the 1st January 2016 and run until the 31st December 2023 In 2012 the UK had 28GW of coal fired capacity. Before 2016 8GW27 of coal plant will have to, or will have already closed. Another round of closures will be scheduled for 2020 or 2023 as the IED forces plant to close, unless investment is made to comply with tighter emission limits. Under the LCPD, Kingsnorth, Didcot A and Cockenzie coal-fired power stations have already closed with a combined capacity of 5.2GW. In addition a further 1GW of capacity at Ferrybridge is due to close before 2016. UK coal plant has successfully worked with regulators to implement environmental permit conditions, and this has resulted in a steady reduction of emissions; in particular SO2 levels have decreased steadily in recent years. Coal plant operators are currently engaged with the Environment Agency in discussing implementation of the IED and the design of the Best Available Technique Reference document (BREF). The application of these policies will determine the ELV’s for existing coal plant until the mid 2020’s. Sensible application is therefore imperative to ensure inappropriate or ‘gold-plated’ emission levels are not imposed. If tighter limits are adopted together with other market signals (e.g. the Carbon Price Floor (CPF), ELV’s that allow unabated gas to run up to 204528, and no acceleration in the pace of CCS demonstration), justifying future investment in plant is more difficult. The likelihood will be that the majority of the remaining UK coal plants will not make the investments to enable full compliance with the IED, and will opt for one of the IED derogation routes, necessitating early closure or extremely limited running. Carbon Price Floor (CPF)/Carbon Price Support The Carbon Price Floor (CPF), which only exists within the UK, was introduced on the 1st of April 2013 and effectively acts to top up the carbon price of the European Union Emission Trading Scheme (EU ETS). It has no impact on Europe-wide emissions as any additional reductions in the UK can, and will, be matched by increases in the remainder of Europe within the overall binding EU cap. The Carbon Price Floor was perhaps not intended just as a tax on carbon emissions, but to stimulate investment in low carbon technologies, such as CCS. Unfortunately it is completely ineffective in this regard and instead the Feed in Tariff with Contract for Differences (FiT CfD) is the instrument that will be used to support investment in CCS. The CPF has a significant effect on UK coal plant. The reduced revenue weakens the financial case for fitting expensive abatement equipment to meet environmental regulations.
27 Tilbury has been included as it converted to biomass in 2011 and closed in August 2013. Ironbridge is also included as it is still opted out under the LCPD although it has converted to biomass. 28 However, As the Committee on Climate Change has pointed out, “Extensive deployment of unabated gas-fired capacity (i.e. without carbon capture and storage technology (CCS)) in 2030 and beyond would be incompatible with meeting legislated carbon budgets..http://archive.theccc.org.uk/aws/EMR%20letter%20-%20September%2012.pdf.
Confederation of UK Coal Producers (CoalPro) – Written evidence (REI0021)
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However, if the CPF had been capped at 2014 prices £9.55t/CO2 and not the £18.08t/CO2 (as it was from next year in the 2014 Budget) then this would have helped provide more certainty for an investment decisions for emissions abatement technology to comply with the IED. The CPF was originally intended to stimulate low carbon investment at a time when significant CCS looked to be on schedule for delivery later this decade. However without CCS, generation would revert to nuclear or renewable plant, or unabated gas. Such an outcome would not provide sufficient diversity, affordability or carbon abatement within the UK generation mix. Impact on investment in the UK The discrepancy between the UK’s CPF and the EU ETS is significant. The difference in the price per tonne of carbon between the UK, Europe and internationally is affecting investment in new and existing fossil fuelled plant. With the ability to enter markets on a global basis, companies look to identify where market conditions are most favourable when making a decision to invest in new build plant. A policy such as the CPF is a key factor that will determine whether or not power generators invest in the UK. Going forward it is essential that urgent and serious consideration should be given to abolishing the Carbon Price Floor (CPF). Overdependence on gas for the generation of electricity The Emissions Performance Standard (EPS) effectively prevents any new coal plant being built in the UK without CCS being fitted. This provides a regulatory back stop and limits the amount of CO2 emissions that a new fossil fuel station can emit. The EPS will be initially set at a level of 450g CO2/kWh and will not be applied retrospectively. This reinforces the existing requirement that no new coal is built without CCS. However, it has been set at a level which allows new gas plant to be built unabated with the ability to grandfather these emission levels out to 2045. Locking in unabated gas for the next 30 years will be worse for the environment than a transitional period of keeping existing coal stations open before moving to CCS. Other electricity system issues The closure of large amounts of coal plant creates problems for the electricity network and its fundamental operation. The loss of large volumes of coal capacity also reduces the frequency response ability provided by coal plants. Such plants are able to react to a reduction in frequency within two seconds, providing an important function for the UK electricity network (hydro and pumped storage take up to ten seconds to respond). The electricity industry is currently working on proposals to alter the Rate of Change of Frequency (RoCoF) at which plant ‘trip off’ to protect equipment; this consultation has been initiated because of the changes expected with increased renewable generation on the transmission and distribution system which are predicted to add volatility to the network
Confederation of UK Coal Producers (CoalPro) – Written evidence (REI0021)
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frequency. The loss of inertia currently provided by directly connected synchronous generators (such as coal plant) will only heighten frequency volatility; this is another critical service that coal stations provide for the UK’s networks. Capacity market Government plans for a Capacity Market (CM) under Electricity Market Reform will be introduced to provide an insurance policy for the UK’s electricity supply during a period of reduced capacity margins. The existing coal fleet can provide cheap and reliable electricity in sufficient capacity over the next 10 years. The option to use the current coal fleet provides an attractive alternative to using new built Open Cycle Gas Turbine (OCGT) and Combined Cycle Gas Turbine (CCGT) which are directly affected by international gas prices and, as demonstrated last year, can be subject to physical supply risks. The UK currently operates a diverse energy mix; this ensures security of supply and best value for consumers. Under its current design, the CM is technology neutral. It is therefore logical that the CM should mirror, or at least acknowledge, the current UK generation mix and the need to diversify the portfolio of generation technologies. The current proposals for the CM, however, seem unlikely to encourage major investment in existing plant. For such plant, under the proposed auction process, capacity contracts will be made available four years ahead of delivery for one year duration. It may be possible to extend this duration to three years if the plant is undergoing major refurbishment. New plant, however, will be able to enter into a longer (unspecified) term. The above makes it unlikely that existing coal plant would invest to meet the more stringent terms of the IED, with no long term contract guarantee. The Mechanism appears to be designed to encourage new gas plant to come forward as a back-up supply for intermittent renewable generation, and risks losing the benefits of cheaper electricity from existing coal plant. Government must provide coal fired plant the opportunity to earn suitable returns on overheads including maintenance, thermal efficiency and emission reduction technology to meet IED emission limit values. This should also consider the period of time it would take to “payback” investments with the prospect of an increasing CPF. In effect, there should be no discrimination between new and existing plant or fuel type. The future of coal-fired carbon capture and storage (CCS) generation UK CCS projects The 2010 Coalition Agreement stated that the Government would support investment in four coal-fired CCS power stations. The current UK CCS Competition was launched in 2012. On the 20th March 2013 DECC announced that the Peterhead CCGT Project in Aberdeenshire and the White Rose Coal Project in Yorkshire were the Government’s preferred bidders for the UK’s £1bn Carbon Capture and Storage Commercialisation Programme. This announcement was a major step towards the UK’s CCS industry being established,
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potentially attracting billions of pounds of investment along with the creation of many high skilled engineering and construction jobs. Government must retain momentum with the CCS industry and ensure it delivers the two CCS projects that can kick start the development of the industry in the UK. The DECC 2012 CCS Roadmap confirms that the UK Government is committed to supporting the development of a robust CCS sector, provided that technology can be shown to be cost competitive with other low carbon technologies. To this end, DECC established the Cost Reduction Task Force to identify opportunities for cost reduction across the CCS value chain. Their recent findings provide a credible pathway, supported by a robust evidence base, for achieving the necessary cost reduction.29
Figure 5 – CCS Cost Reduction Trajectory The White Rose Project will capture 90% of the carbon dioxide from a super-efficient coal-fired power station. As a separate associated project, National Grid will construct and operate the CO2 transport pipelines where the CO2 will then be stored in undersea storage facilities. The White Rose Project itself is expected to create approximately 1,250 new construction jobs over the three-year plant development period at the Drax site and at least 60 operational jobs at the new plant as well as additional indirect supply and maintenance posts. It is encouraging that the Government, in its response to the findings of the Cost Reduction Task Force30, announced its intention to explore the option to support a FEED study for a
29 CCS Cost Reduction Taskforce, The Potential For Reducing The Costs of CCS in The UK, Final Report, May 2013.
Confederation of UK Coal Producers (CoalPro) – Written evidence (REI0021)
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‘Yorkshire / Humber CCS Trunkline’ as part of the White Rose Project. This Yorkshire / Humber CCS Trunkline’ is a critical opportunity to cost-effectively support other coal CCS projects in the region. CfD price for CCS The Feed-in-Tariff with Contracts-for-Difference (FiT CfD) under EMR will be the key mechanism driving investment in low-carbon technologies, including CCS, renewables and nuclear. Developers of coal CCS projects outside of the current competition require access to CfDs if these projects are to be constructed. However, at present, details of the CfD mechanism are still awaited, to ascertain whether it would meet the necessary investment criteria needed to attract finance into CCS projects. There is also significant uncertainty over the market conditions required by developers to continue investing in projects. Clarity is urgently needed on:
recognition of the characteristics of the CCS chain (capture, transportation and storage); and variable fossil fuel prices as a significant operational cost
transparent and predictable allocation process for CCS, with details released as soon as possible
a clear ambition to use EMR and CfDs to support coal CCS projects outside the current competition to advance the commercialisation of the technology
an initial strike price which encourages swift investment. Government must commit to develop coal CCS projects outside the current competition with support provided by CfDs. These projects should begin operating before the end of this decade. The statement is welcome in the response to the CCS Cost Reduction Task Force, that the Government expects that deployment of a second phase of CCS projects is needed – possibly developed on a similar timeline as well as subsequent to the competition projects – and urges these to include coal CCS projects. Looking further forward, the Climate Change Committee has argued that the Government should establish a CCS Commercialisation Programme, which sets out a clear ambition to deploy a minimum of 10 GW of CCS by 2030, in order to commercialise the technology and provide the UK with a portfolio of low carbon technologies that can deliver substantial emission reductions beyond 2030. Setting a minimum CCS volume would allow the technology to be commercialised while enabling coal CCS to secure a larger proportion of the electricity market if it proves cost-competitive with other low-carbon generation sources, thereby delivering the UK’s carbon reduction targets at least cost to the consumer. International projects Approximately £13.74 billion has been invested internationally in CCS technology with approximately 234 CCS projects either planned or operational.
30https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/251005/CCS_CRTF_Govt_Response_and_CCS_Update_15_Oct.pdf.
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Boundary Dam coal CCS In Canada, SaskPower has built the Boundary Dam CCS project. This is a 110 MW coal power plant with retrofit CCS technology due to start operating in 2014. In November 2013 the Commons Energy and Climate Change Select Committee visited this site and the Committee subsequently called on the Government to speed up support for CCS in the UK. This leading-edge project will determine the technical, economic and environmental performance of CCS technology. The total cost of the project is estimated to be $1.24 billion, with $240 million from the federal government in 2011, of which about $180 million has already been spent. The provincial government is also supporting the project. Employment includes 20 at the R&D stage, peak construction employment of 1,500 and 41 operational employees31. Kemper County IGCC Project In the USA, Mississippi Power is building a new build 582 MWnet coal-based electric power plant using an Integrated Gasification Combined Cycle (IGCC) design called TRIG technology. The plant will capture 3.5 million tonnes per annum of carbon dioxide (CO2) which is around 65 per cent of its annual CO2 emissions. The project is scheduled to become operational in 2014. CoalPro conclusion for the House of Lords Science and Technology Committee inquiry into Resilience of Electricity Infrastructure The UK is in a unique position to retain and life extend its existing coal plants and develop CCS technology for coal, with its resources of technological competence, finance, manufacturing expertise, natural storage advantages in the North Sea and an indigenous coal mining and coal power industry committed to powering the UK long term. The UK has a significant coal reserve base which will not be accessed unless actions are taken within the coal generation market. There is a real concern that existing coal stations will have closed before CCS technology can be established, with the consequence that:
Indigenous coal production will have disappeared together with the UK’s well established coal supply infrastructure
Loss of over 10,000 direct jobs and the skills associated with these roles
A lost opportunity to develop a world class coal CCS industry based on UK coal
Reduced coal generating capacity by 18GW between 2016 and 2023 as existing unabated coal plant is forced offline due to high and rising taxation under the proposed carbon price floor trajectory
31 Sask; TUC submission to the current ECC Inquiry into CCS.
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A sudden significant loss of income for the Treasury as coal plant is closed earlier
than planned or anticipated
Security of supply diminished as the UK becomes overdependent on imported gas for electricity generation
Increased costs for consumers and energy intensive industry
19 September 2014
Rupert Darwall, the Renewable Energy Foundation and Dr Robert Gross, Imperial College London – Oral evidence (QQ 167-175)
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Rupert Darwall, the Renewable Energy Foundation and Dr Robert Gross, Imperial College London – Oral evidence (QQ 167-175) Transcript to be found under Dr Robert Gross, Imperial College London
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The DEMAND Centre, Lancaster University – Written evidence (REI0037) Introduction We welcome the chance to contribute to this inquiry. The Dynamics of Energy Mobility and Demand (DEMAND) Centre32 is based at Lancaster University and brings together a consortium of researchers from eleven universities and a range of non-academic partners. The DEMAND Centre is one of six research centres funded by the Research Councils examining end-use energy demand from different perspectives.33 In total, the Centres represent a £43m investment aiming to ensure the UK is recognised as an international lead in this area of research. The DEMAND Centre was established to contribute evidence on a vital aspect of energy research that has traditionally been neglected: an understanding of the underlying dynamics of energy demand. The Centre tackles the fundamental question of what energy is for. Achieving greater energy efficiency is important, but the trend is often towards more resource intensive standards of comfort, convenience and speed. We lack a sophisticated understanding of how these trends take hold and of the underlying dynamics of demand itself. The DEMAND Centre takes this problem as its central challenge. The neglect of this fundamental question means that policy and market arrangements for electricity are insufficiently focussed on the demand side. Whilst they may engage with questions of efficiency, demand response and ‘load shifting’, they do not effectively consider the changing dynamics of why and how electricity is being used in the first place, thereby overlooking an important domain that is potentially open to influence and intervention. We therefore begin this submission with a statement about how our approach could inform the central topic of the Inquiry: The resilience of UK electricity infrastructure. We go on to provide answers to some of the questions posed by the Inquiry, in order to illustrate and give examples of our approach. How can an understanding of end-use energy demand help build the resilience of UK electricity infrastructure? Our central message for the Inquiry is this: In interrogating the future resilience of electricity infrastructure, it is important to consider the patterns of possible future end-use energy demand, rather than taking these for granted, and to engage with the underlying processes through which energy demand is produced, sustained and changed.
32 http://www.demand.ac.uk. 33 http://www.eued.ac.uk/home.
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Debates about energy futures routinely proceed without reference to primary questions about what energy is for, about the sets of ‘end uses’ on which energy demand depends. Yet energy is not used for its own sake, but as part of social practices like cooking, commuting to work, watching TV or conducting meetings. How these practices are carried out is shaped by, and influences expectations of infrastructure in a wide sense – not just the electricity infrastructure, but also transport infrastructures, the built environment, ICT networks and so on. It follows that (i) future changes in these practices and infrastructures will have consequences for the resilience of the electricity system over future decades, and (ii) that the resilience of the electricity system could be strengthened through policies which have impacts on these practices and infrastructures. The central aim, a more resilient electricity system, could therefore be achieved in part through the pursuit of changes to patterns of energy demand rather than focusing only on the supply side. And these changes may, indeed, prove cheaper or have wider social benefits than the more commonly-considered alternatives. At the moment, these options are not ‘on the table’, so their costs and benefits (compared to other interventions) are not properly evaluated. Some particular lessons that emerge are as follows: 1) We should not assume that future demand will look like current demand Current government policies rely on scenarios and analyses of options for promoting efficiency and decarbonising energy supply whilst maintaining current standards of living. In effect these methods presuppose that present practices involving energy use will remain the same far into the future. This is highly unlikely: ways of living change all the time, both potentially leading to escalations and reductions in future energy use. Our work on the histories of home infrastructures and domestic energy use, for example, shows how different energy using practices have changed from the 1940s to the present day.34 Ideas of ‘normal’ standards – of heating (e.g. room temperature), bathing and laundering (hot water) – evolved alongside the introduction of gas and electricity and the relative decline in solid fuel between the 1920s and 1970s. This longitudinal analysis can help in understanding how demand will be, and could be, shaped over the coming decades. A recent DECC commissioned report35 notes that social changes are centrally important to patterns of future demand, but acknowledges that current modelling approaches engage with these in only very limited terms. A further key point arising from our work is that future innovations, including those designed to enhance the resilience of the UK electricity infrastructure, will themselves have an impact on demand.
34 DEMAND Centre project 3.1. This project will produce a series of papers to be published in 2015, some focusing more on the historical data, others on the role of professions and planners, and on the ways in which infrastructures and social practices shape each other. 35 ‘An analysis of D3 in DECC’s energy system models’ https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/341300/Analysis_of_D3_in_DECC_energy_system_models.pdf.
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2) We need a better understanding of the social dynamics of energy demand To the extent that energy demand is included within energy policy, it tends to be considered either in terms of technical efficiency or the behaviour of individuals - with the implication that such behaviour can be changed through incentives or education. However, the research of the DEMAND Centre shows that energy demand predominantly depends not on individually chosen behaviours, but on the shared social practices that make up accepted normal and everyday patterns of living, working and moving around. In considering changing patterns of demand what is currently missing therefore is a sophisticated analysis of the development of end use practices and the constant adaptation of the hard and soft infrastructures (gas, electricity, transport, logistics systems, organisational procedures) on which these depend. Such an analysis would identify the creative potential for future transformations in energy demand across different sites and timescales – including the introduction of more seasonally adapted forms of provision (in transport, at home and at work); in more forgiving and flexible interpretations of comfort; and through the systematic reconfiguration of institutions and incentives that reproduce resource intensive solutions/ways of living.36 3) Energy policy does not influence end-use energy demand as much as other policy areas: land-use planning, transport, even health and education all influence the underlying dynamics of energy use The DEMAND Centre uses the term ‘implicit energy governance’ to describe the implications of non-energy policies on energy demand. One simple example is that changing the length, timing, or co-ordination of school holidays would have an impact on the ways in which daily lives are scheduled, and hence on the patterning and timing of when and how much energy is used.37 There are many others. Our research will, for example, shortly begin to analyse how policies in, for example, the areas of health, higher education and the military have implications for energy demand.38 Developing this understanding reveals how policy agendas far beyond the narrow conception of ‘energy policy’ affect energy demand and therefore have implications for how resilient current and future supply infrastructures may prove to be. Responses to consultation questions Below we respond to a number of the Inquiry’s consultation questions in order to illustrate how a focus on end-use energy demand could contribute to improving the resilience of the UK’s electricity system.
36 See DEMAND Centre Theme 3. 37 http://www.demand.ac.uk/24/10/2013/school-holiday-shakeup-brings-unintended-consequences-article-in-the-conversation/. 38 See DEMAND Centre project 4.3.
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Short term (to 2020): How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base? As described above, there is a major gap in the evidence base on the demand side, with very little knowledge about why electricity is used at different times, including during peak periods. A review conducted by the DEMAND Centre of the measurement of domestic energy consumption, shows that linkage of measured energy consumption to what people actually do in the home is extremely rare.39 If we do not know what people are using electricity for at peak times, we cannot begin to influence these patterns in effective ways (in order to ‘smooth peaks’, or ‘fill troughs’). We are undertaking some initial work in this area (including in collaboration with EDF R&D), but recommend developing a much stronger evidence base about what electricity is for used at different times (in domestic settings and for other reasons) in order to inform policy oriented around peak demand issues. With such understanding the possibilities of and constraints on ‘flexing’ demand will be better informed, including giving insight into the potential implications for different social groups. Short term (to 2020): What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’? Here we note the use of ‘keeping the lights on’ as an off repeated indicator of successful energy policy, and a commentary from DEMAND researchers that notes: “Instead of blindly insisting on the importance of keeping the lights on (and all that the phrase stands for) the real political challenge is to bring questions of demand into view. This is not just a matter of technological efficiency. What is needed is a fundamental debate about how much energy is enough, what does it mean to establish ways of living that call for much less power than we use today, and just how many lights could or should be kept on?” 40 Short term (to 2020): Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure? Over the next six years, a much better understanding of end-use energy demand will be developed, both at the DEMAND Centre and at the other five RCUK Centres. Given that all of the Centres are working with partners in industry and government, this should provide a good evidence base to inform such decisions. One example would be the understanding we hope to gain about flexibility of demand and our demand-side ability to cope with or adapt to greater intermittency of supply that might be a feature of some plausible energy futures. Medium term (to 2030): What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models?
39 http://www.demand.ac.uk/10/02/2014/theme-1-report-the-rhythms-of-demand-january-2014/#more-1664 40 Allison Hui and Elizabeth Shove ‘All of this talk about lights hides bigger challenges’ http://www.demand.ac.uk/14/11/2013/keeping-the-lights-on-the-conversation-13-november-2013/
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As explained above, the dynamics of energy demand are insufficiently accounted for in energy modelling. Demand projections are too often based upon current assumptions, practices and standards, all of which are likely to change over time. The default strategy is to take present patterns of energy use entirely for granted, treating the perpetuation of current ‘standards’ as an unquestioned, non-negotiable part of the equation and focusing exclusively on the efficiency (or otherwise) with which these might be met.41 This is insufficient, including in the face of EU demand and carbon reduction targets. The DEMAND Centre is working to help Transport for London to examine its long term travel demand forecasts. Our contribution will expand the consideration of demand drivers beyond the traditional transport demand variables of price, availability, income and quality of service, to include factors such as changing duration of work, increasing trips for care and changes to shopping patterns brought about through retail innovation. These are indicative of the types of information that might be needed in developing sophisticated modelling of future electricity demand. Indeed, looking ahead, if the government’s low carbon vehicle strategy is successful, demand for transport becomes a key part of electricity demand over this period. Medium term (to 2030): What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? Medium term (to 2030): Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? When considering long-term infrastructure and its relationship to resilience, it is important to consider the interactions between energy infrastructure and other infrastructure, such as ICT and transport. The DEMAND Centre is currently conducting a series of place-based studies to examine how infrastructures are designed and adapted, and how this changes practice.42 One example is the debate about switching to electric cars. The assumption that tends to be made, in modelling and policy, is that private car use will be retained, by substituting petrol for electric vehicles. However, as a recent OECD report43 suggests, they will only save carbon emissions in the context of a massively decarbonised electricity supply system, re-engineered to cope with increased demand. Further, it ignores the fact that technological and social change influence each other. The future is not simply the same as the present, with technological substitutions.
41 DEMAND researchers have for example considered assumptions embedded in the DECC 2050 modelling tool, discussed in “What is Energy For?: Social Practice & Energy Demand”, Elizabeth Shove and Gordon Walker, Theory, Culture & Society 2014, vol. 31 (5) 41-58; Shove, E. (2015) ‘Linking low carbon policy and social practice’ in Strengers, Y. and Maller, C. (eds) 'Beyond Behaviour Change: Intervening in social practices for sustainability' Routledge. 42 DEMAND Theme 3.1 Adapting infrastructure for a lower carbon society. 43 http://www.internationaltransportforum.org/jtrc/DiscussionPapers/DP201203.pdf.
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Instead, it would make more sense to assume that electric vehicles, with shorter ranges, long charging times and a new electricity infrastructure, will themselves change the practices that underpin energy demand. Electric cars are likely to be owned, managed and used in a different way to petrol cars and may also have an impact on the range of destinations to which people travel. There may be the opportunity to promote modal shift, to other forms of transport, including cycling for example. Over time, the ‘need’ for cars may change. The current ‘need’ for cars is the outcome of a historical process which includes the development of out-of-town supermarkets and associated forms of land use, the decline of high street shops and the gradual shift in shopping habits and routines. The ‘need’ for the private car is something that should be within the realm of policy intervention – through the planning system, for example.44 23 September 2014
44 “Unsustainable practices: Why electric cars are a failure of ambition”, Nicola Spurling & Dan Welch, March 2014 http://www.demand.ac.uk/05/03/2014/unsustainable-practices-why-electric-cars-are-a-failure-of-ambition/.
The DEMAND Centre, BEAMA and BDO LLP – Oral evidence (QQ 114-123)
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The DEMAND Centre, BEAMA and BDO LLP – Oral evidence (QQ 114-123)
Evidence Session No. 10 Heard in Public Questions 114 - 123
TUESDAY 2 DECEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Manningham-Buller Lord Peston Lord Rees of Ludlow Viscount Ridley Lord Sharp of Guildford Lord Wade of Chorlton Lord Winston ________________
Examination of Witnesses
Professor Gordon Walker, Co-Director, the DEMAND Centre, Dr Howard Porter, CEO, BEAMA, and Michael Ware, Partner for New Energy and Environment, BDO LLP
Q114 The Chairman: Welcome to this session of the inquiry we are doing on resilience in electricity. We are being broadcast. Would you like, therefore, to introduce yourself for the
record? If any of you would like to make an introductory statement please feel free to do so.
Perhaps Mr Ware would like to start.
Michael Ware: Good morning. Thank you for inviting me along. My name is Michael Ware. I am a partner of BDO, the accountancy firm. I specialise in project finance and renewable energy, and our role is to raise money for projects for both generation capacity and also some demand-side response, although there is very little of the latter at the moment. I am here to take questions.
The Chairman: Dr Porter?
Dr Porter: I am CEO of BEAMA, the trade association for the electrical manufacturing industry. I think we have been invited here today because we have various projects with manufacturers looking at the integration of smart metering, smart grid, electric vehicles, heat pumps and a variety of other equipment of that nature. We have all the manufacturers
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of all the smart metering equipment within our membership and, therefore, we have a lot of experience in those areas and I am asked to share those with you today.
The Chairman: Professor Gordon Walker?
Professor Walker: I am Co-Director of the DEMAND Centre at Lancaster University. I should explain that DEMAND is an acronym that stands for the dynamics of energy mobility and demand, and we are one of six research centres that were set up last year by the Research Councils in the UK to do research on end-use energy demand. We are a social science-led research centre, so we have particular interest in the dynamics of energy demand, how they change with social dynamics and social change. I would like to say that it is particularly welcome that there is a chance to talk about demand as part of this inquiry process. For a topic like the resilience of electricity infrastructure, it would be easy perhaps just to talk about the infrastructure, the supply side and the transmission and distribution, and to forget that the whole point of that is because of the demand relationship and the resilience of the relationship between demand and supply. So it is very good to have a chance to discuss all of this with you.
The Chairman: Thank you. We will indeed be talking about the demand-side response in this session. Lord Peston, would you like to start?
Q115 Lord Peston: Yes. What I would really like to get from you is both clarification of what we mean by dynamic management of demand and then examples of how we might use it. Am I right that the whole point of the dynamic approach to demand is to move demand, by one means or another, to where we would be using our generating system more efficiently if the demand occurred at that time rather than that time? Are there mechanisms—wearing my economics hat, price would be the one that immediately pops into my head—whereby, if you demand at that time rather than this, it will be cheaper, whereas if you demand then it will be much dearer? Another might be special forms of contract. Would that be included in all of this?
I was speaking to someone with a smart meter—although I have never found out what the point of it is other than the fact that it flashes lights on all the time when my wife switches on the dishwasher, for example, which means it is expensive at that point. But I take it smart meters are also an important ingredient of this, but, as I say, speaking as a customer, it is not obvious how that influences demand as far as I am concerned. So am I right that those are the topics we ought to be talking about, and then can you give us examples of the latest state of thinking of how you are operating this dynamic system? I am not sure who wants to go first.
Dr Porter: Certainly we could dissuade you from your view that smart metering does not do anything. I think the system you have in your property is not the final design. That is an early design, before the mass rollout. Certainly in demonstrations we have done—I think links were sent to you all, if you looked at that—we demonstrated that, with a smart meter infrastructure that will be planned from 2015 onwards, that can be the basis of the demand response in the future. I am talking primarily about domestic buildings at the moment although it is relevant for non-domestic, but unless you have that technology base within the building it is possible but very difficult to have a demand-response technique in place. Once you have that technology in place—we could discuss all day about when and how, but we will leave that for the moment—we believe that the functionalities of that final smart meter
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rollout are sufficient in our UK design to allow a wider range of uses and functionalities than the limited functionality of currently installed equipment.
Now, if you look elsewhere in Europe, that is not the case. There is lobbying going on in Europe to make sure that more of the smart meter rollouts have more functionality to allow these things to be possible following rollout, but the UK has the most functionality within the smart meter rollout, allowing more of the add-on benefits that, not all of which are immediately possible on day one but, it is then a case of using those functionalities as we go forward. That is probably the opening from our side to kick us off.
Michael Ware: There are a couple of points I would add to that. Looking elsewhere in the world, we see that demand-side response has particular potential on the domestic side, but I would say more in the commercial and industrial space. I think a recent auction in the US generated 11 gigawatts of capacity through demand-side response compared to only about 4 or 5 gigawatts of generation capacity in the same auction. Industry is ready to do this and the technology is ready to do this.
However, there are two problems. First, this is an investment decision on behalf of the demand-side response aggregators. This involves physically putting pieces of kit into industrial and commercial situations and in the capacity auction as put out at the moment I can only buy a year’s worth of capacity as a demand-side response, so my payback period has to be very compressed. However, for generation, up to 15 year capacities are available. One area the Government has wrong is that the contracts for demand-side response are too small to trigger significant investment on behalf of the investment community.
I think the second point here is about companies seeing that this technology is reliable and that it works. Where the public sector could play a very significant role is to be an exemplar for demand-side response. A recent study by the Cabinet Office, taking the whole public sector estate, particularly health, showed that less than 10% of the public sector were looking at any form of demand-side response and the majority of respondents—over 60%—had no plans to do so whatsoever for the foreseeable future.
Lord Peston: That is looking at the public sector?
Michael Ware: Yes. The Cabinet Office survey of the public sector estate said basically, “Are you looking at demand-side response?” and the overwhelming answer was, “No”. Less than 10% are doing anything at all and over half had no intention to do anything. I think the missed opportunity there is for the public sector to demonstrate to industry that the risks of demand-side response are overstated and that it can be made to work.
Professor Walker: In broad terms, on your opening question in terms of, “Is our understanding right”, I would agree, yes, your understanding was right. The idea of managing demand over time is quite familiar. We have had Economy 7 since the 1970s, which is a very basic form of what is now being rolled out in a much more sophisticated form, through smart meters with the ability to do lots of different work in terms of the time periods over which you set peak pricing, the degree to which you have a price lift and the regularity or the irregularity of those peaks. It could be that you just go to a peak pricing scheme during the critical periods in the winter when there is strong pressure on the system.
The other point is that there is a lot of activity going on already in the non-domestic sphere. At my university we get these things called triad warnings on a regular basis. We get emails around everybody in the university saying, “Between 3 pm and 5 pm on this Wednesday
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afternoon please try to turn things off,” because we have a contract with an aggregator, which means it is beneficial to the university to try to do that. There is lots of activity already out there in the non-domestic sphere. I have heard a lot of arguments that there is a lot more potential there than has been realised.
Some of what is happening at the moment is basically back-up generators being switched on, for example, at hospitals and IT companies. They have big back-up generator systems to deal with blackout situations and these contracts are enabling them to turn on those, often diesel, generators during these periods. That is not necessarily the best way of achieving the objectives we have, particularly in terms of carbon emissions, but I think there is a lot more than can be done and the new demand-side balancing reserve is opening up the possibility of demand response to a greater range of companies and businesses and I would absolutely agree there is lots of potential in the public sector.
Lord Peston: There is nothing original about dynamic management of demand. We all know in London restaurants nowadays they do a pre-theatre supper as long as you eat early because they have spare capacity then and that is when they would like to use it up, but I am very concerned about your remark about the public sector. There are those of us who are very keen on the public sector, and I certainly am. I have always argued that the public sector should always be taking a lead in the efficient management of resources, which has got me into serious trouble with the Labour Party in the past, but that is another matter. Why is it that the public sector is not taking the lead in responding to the dynamics of this situation? Surely the management must have some understanding that, the more economical they are, the more likely they are to achieve their aims. Do you have any views on where the problem lies?
Michael Ware: If we look at demand-side management, which is relatively new, but also micro-generation in the sense of the public sector putting in solar panels, wind farms and so on, there are two points there. I think the amount of energy generated by the public sector from the estate in this country is less than a quarter of what Germany achieves from the same sized public sector estate, which is a reflection of how far down the road the Germans are in terms of generating renewables generally. Secondly, there is no overarching target or requirement upon the public sector to either generate its own energy or to implement demand-side response. This is purely speculation, but I suspect that, as a manager in a public sector environment faced by competing demands upon capital, demand response and micro-generation are probably lower down on my list of priorities than other constraints because the payback period is much longer and the impact is less visible.
Q116 Viscount Ridley: On the smart meter point again, am I right in thinking that 18 months ago the Government delayed the deployment of smart meters by 12 months and am I right in thinking it did so again last month? Is this turning into a giant public sector IT project that goes wrong, and is that getting in the way of seeing the effect that smart meters would have on demand-side response?
Dr Porter: First of all, I should hope not. We had a meeting with DECC last week on this particular issue about the delay and I know the whole department and everyone involved is very keen that this is not seen as being another delay, or as a reluctance to go forward. I think the issues are in terms of the way in which the structure is put together and how the communications are put in place. There are some testing problems in how the final solutions are put together, which requires some level or contingency. That is our interpretation
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directly from the DECC officials. We also understand that the whole department and the Minister have said to the civil servants and the contractors, Capita, that there should be no further come-back for more time, “This is it, so please make sure that every contingency you need is in the contingencies now in the consultation”. It is a consultation. It may come back that it is rejected. I do not think it will be.
Viscount Ridley: Capita has asked for more money, though.
Dr Porter: I hasten to use the word “small”. Compared to the contract, there is a small addition. It is still quite a lot of money but, yes, there is an increased amount of money. Now, from our perspective, looking at the manufacturers of the equipment, we are not questioning the decisions on how the structure is put together. We could spend all day discussing that, but that is what there is and, therefore, we are working at best to make sure everything is ready at the time of rollout. You are absolutely right that there is likely to be another delay—or contingency, depending on how you wish to sell that message—but it probably allows a little bit more time to get some of the complexities sorted out to get us there. I had this conversation this morning with other colleagues on other things that we are planning to do on the back of this. It does mean that the rollout at the moment will be squeezed by nine months because the end of 2020 has not been shifted or is not planned to be shifted, so it is squeezed. At the moment we believe that is still doable and it probably just means that the availability of that smarter infrastructure is later, but if you as a typical consumer were going to get your smart metering kit in 2018 you are probably going to get it in 2018 as well. It just means that the first bit is scrunched a bit.
Viscount Ridley: Until then it is only Lord Peston who gets it?
Dr Porter: No, at the moment there is something like 1 million smart meter systems in place. I am not going to give any advertisements for any company here, but if you are with one energy company you will be offered them a lot. If you are with other companies you will less likely to be offered them. I am sure you probably know who I am talking about. I know the department is very keen to encourage the other energy companies to follow that lead in offering consumers smart meters that are not fully integrating with the system earlier than the kick off date but, back to my colleague here, that is a commercial decision from those companies whether they proceed ahead of the game or not.
Q117 Lord Wade of Chorlton: Just as a follow on from that, in one of your earlier responses you referred to smart meters as having facilities in the UK that can obviously allow the electricity suppliers to learn more and more about what the customer does with it. I get the impression that is what you are suggesting. What is the implication of that: that if you are not a good customer they will turn you off? Does that suddenly put the power in the hands of the supplier rather than the hands of the customer? That is absolutely opposite to what I believe in. How do you see that unfolding?
Dr Porter: An awful lot of work has been put into this issue by all parties, including the utilities, manufacturers and the department. There is a very clear delineation of who gets the data and the security around the system. In fact, it caused some problems in terms of connecting other things because there is so much security around the smart meter mandated piece that it causes problems for how you connect to it. Later on I will come on to how that will connect in the future, but within that scope there has been a tremendous amount of work done to get the privacy sorted out and it is very much the case that the
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energy companies have been given pretty stringent instructions from DECC and now the regulator, Ofgem, in making sure this is very customer-centric in its rollout. There is a danger, as you point out, that if you are a non-payer you may be cut off. The rules are still the same. The rules on how an energy company will react to those customers does not change at all and, in fact, where you have at the moment prepayment, which is where you go along and you buy a token and you use this for your meter, the new technologies will radically change that idea. There is a different term used now. Prepayment—or payment before use, shall we say—will increase because of the smart meter rollout rather than decrease because consumers will feel they are more in control of their spend by pre-ordering and putting it into their system rather than waiting for a direct debit or a bill, or an estimated bill as it is now.
Lord Wade of Chorlton: There is a difference between somebody being cut off because they do not pay and the choice of electricity they do buy. Surely, if a person is prepared to buy the electricity, what they do with it is entirely a matter for them.
Dr Porter: Indeed. There is absolutely no intention from any of the players to cut more consumers off as a result of smart metering data—
Lord Wade of Chorlton: If they have the information how can it end up—
Dr Porter: There is the policy that it is down to the customer to decide and, if we go into other areas of demand response or other aspects within domestic buildings, the philosophy and the rules and regulations all thus far, and I think will be in the future, are down to the consumer to decide. If a consumer is offered a demand-response package by some tariff or some other methodology through their smart metering infrastructure, it is entirely their choice whether they take up that offer or not.
Now, it may well be the utility highlights how beneficial it is and, if it is beneficial for the country or beneficial for the climate or beneficial for the pocket, it is entirely up to the utility—or aggregator if that comes into domestic in the future—to make that offer. However, the customer can say, “No. I hear what you are saying. I do not want that”. That is the same as in the commercial arrangement my colleague has mentioned. If a public sector or factory owner says, “I am not interested”, no one is going to force them. It is exactly a choice for the consumer whether or not they connect.
Q118 Baroness Sharp of Guildford: To some extent you have already answered this question. To what degree are current policy and market arrangements for electricity insufficiently focused on the demand side? In particular, does the Government have a sufficiently joined-up approach to future electricity security, including demand-side measures? Does the National Grid have the balance right between supply and demand-side measures? Does the capacity market itself provide sufficient incentives for demand-side response?
Michael Ware: There are two specific points I would like to make there. The first is the capacity auction. Our understanding is that demand-side response contracts are much shorter than they are for generation, which is a disincentive for investors to invest in demand-side response. For industrial and commercial users, this is an investment requirement. The aggregators have approached us in the past to say, “We want to raise £10 million, £20 million or whatever to roll out demand-side response technology across a customer base of commercial and industrial users”, but the payback is so compressed
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because the amount of capacity they can sell into the auction is limited to a year. I think that is an obvious amendment to make to the policy that would bring in investment much more quickly.
Secondly, you asked about joined-up Government in this and I think there is an interesting point here. We have a Government that is faced with capacity constraints across the grid and yet other parts of DECC are cheerfully promoting policies that will increase demand upon the grid—in particular, I mean electric cars and heat pumps. We spend quite a lot of time thinking about electric cars but, to our mind, there seems to be no end-point as to what percentage of the UK fleet the Government is trying to persuade to shift to electric and, secondly, what the impact upon the grid will be of shifting that percentage across. Through our conversations with DECC we have never found the person who knows the answer to those two questions and I suspect they do not exist.
Dr Porter: Keep on looking.
Michael Ware: We have a Government that is actively giving people £5,000 grants and free electricity to switch to an electric car, irrespective of their personal means, in a situation where this Committee and a lot of Government is thinking about capacity constraints upon the grid. In answer to your question, I do not think that is a good example of joined-up Government.
Baroness Sharp of Guildford: Also the example you gave of the public sector not taking advantage of the demand-side measures that are already in hand.
Professor Walker: I would also question whether the Government is sufficiently ambitious in its overall objectives because, if you take the 2050 carbon scenario seriously and the targets seriously, we are talking about major reductions in energy demand overall—not just the time of use but the overall energy demand reduction.
There has been a lot of debate in Europe recently about whether there should be a mandatory Europe-wide energy reduction target and proposals came from the Parliament for a 40% reduction in overall demand by 2030. Unfortunately, from my point of view, our Government was instrumental in blocking that and the outcome has been a 27% reduction—we are not quite sure why exactly 27%—by 2030 but not on a mandatory basis. I think overall there is a lack of ambition and a lack of realism about how much you need to bring down energy demand, particularly if you are electrifying heating and vehicles. You cannot be doing that at the same as allowing energy demand to stay pretty much where it is or to allow it to increase overall.
Dr Porter: I would tend to agree in slightly different ways to my two colleagues here because, again looking from a manufacturing perspective—the people trying to develop kit that will deliver this—there is probably above all this something like a 20% or 30% reduction in electricity usage possible from all building types and all factory types. Currently we are doing some work within the department to try to highlight this. You almost want to do that before you start thinking about how you do demand-side management.
Q119 Baroness Sharp of Guildford: I was also going to ask you about building regulations and whether they were tough enough.
Dr Porter: Well, we could be here all day talking about the pros and cons of that. There are enormous opportunities to reduce the use of energy before you start thinking about
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demand response and the other types of things that we have been talking about, such as electric vehicles and heat pumps and electric heating. We were part of a big study launched last week by Carbon Connect and in that independent people looked at all the scenarios to get you to 2050 and I think the increased use of electricity in terms of heating and transport featured in four and a half of them—I am not quite sure what happened to the other half. We are somewhat biased given we look after electricity manufacturers, but all the work seems to go in that direction because if you want to decarbonise you do not build more coal-fired stations or more gas. You have to produce it with renewables or nuclear or other storage methods you were discussing earlier. If you have that scenario by 2050 you have to have achieved the appropriate use. You take off the road the other vehicles, a little bit like the way in which the rail industry transferred to electric trains 30 or 40 years ago, when I was a young lad.
Michael Ware: Something like that.
Professor Walker: Not entirely.
Dr Porter: Not entirely, but it has been going ever since. Electrification is seen as the way you do trains. No one says the best way is to go backwards and it is a similar philosophy going forward. However, my colleague is right, you have to manage it in the right way.
On the flip side of the electric vehicle area, many commentators say the storage available in the batteries of electric vehicles, if plugged into the network via the smart meter infrastructure in your home—or, indeed, in the car park of the office building where there are 10 of them plugged in—is, if you have a smart grid, a very usable level of storage.
One other point we will make here is that, within that smart system and how you manage things, an area of storage that was not mentioned in the earlier session—which I was here for—was a very straightforward thing called electric hot water. In the old days you used to use Economy 7, which I think my colleague mentioned, where you could heat your hot water overnight with the off-peak energy. Some of our manufacturers are now designing the smart technology with a very simple emersion heater, basically, that is available—if you have the right technology and the consumer access devices that allows this, when free power, renewable or nuclear or whatever is available—to remotely charge the hot water up to the right level, controlled by the control system. This means the consumer, again if they are signed up to a deal, can basically get low-cost hot water charged at low-carbon times of day. That is a very low-tech version of the storage area, but it is integrated into a smarter way of handling this and part of the demand response within a building.
Viscount Ridley: I wanted to declare an interest, Chairman, which I forgot to do. Mr Ware’s essay on electric cars won a prize that is named after me, which was judged by the Spectator magazine last year.
Lord Broers: As we are into declaring interests, Chairman, I should in this session declare the fact that I held the BEAMA professorship of engineering in Cambridge for 14 years and so I am a very strong supporter of what BEAMA does.
My question is: in the future, as electricity generation is decarbonised, what role do you expect demand-side measures to play in ensuring system resilience? We have discussed this a lot, but there are a couple of very specific questions here. For example, do you think we could operate at a lower derated capacity margin as a result of demand-side techniques? What would the economic implications of this be?
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Dr Porter: I am reading from my notes here because I did ask my colleagues who know about this before. Where demand response has been cost effective, particularly in the US, we understand that that represents 6% of peak capacity and that equates to Hinkley Point, or about 3.3 gigawatts. That is the use of similar technologies—not the same but similar technologies—within a US base. Certainly the DSR in the US has saved some $12 billion in one year. That is clearly a different scale because we are not at US scale, but the 6% is probably worth putting in mind. That is certainly what has been delivered within mainly a domestic context—with some commercial, I think, in that situation. You may have some further figures you can add in.
Michael Ware: I think there are two concepts there that we are conflating. We talk about renewables and the role of renewables in demand-side response. I would go back to storage. Storage marries better with renewables in the sense that renewables have two problems: intermediacy and capacity on the grid at the places where it is feasible to do a renewable energy project. As your Lordships will be aware, one of the problems in this country is that the grid is not uniform and parts of Cornwall and Norfolk are now almost at capacity because of the amount of renewable generating capacity that is in place during the summer months. Only last week one of my clients was complaining to me that they developed a wind farm in Cornwall and were then told by the district network operator that they could not access the grid in daylight hours because there was physically not enough capacity on the grid to take more power in during the day because of all the solar. I think the answer to that in some ways lies in storage. Storage can address the issues of intermediacy and it can address issues of capacity. In that situation my client could store the energy in a battery and then feed it into the grid in the evening and during the night. However, I do feel that storage is a very undeveloped technology. The battery has not fundamentally changed in over 100 years. It is a very undeveloped embryonic technology that is not widespread in this country and it is not particularly widespread elsewhere.
At the moment DECC have placed it within the capacity auction, almost as an afterthought it feels to me, whereas I feel it would have been much better placed under the renewables umbrella of contracts for difference because one can get much more certainty, from an investment point of view, around investing in storage. If it is placed in the capacity auction I am asking my battery-based storage system to compete with the established technologies when I am not at that point and I get much shorter contracts than I do for generation. Under the CfD regime, I am competing with less established technologies in the sense of renewables and much longer contract periods. I think that is much more attractive to investors. The role of the Government there is promoting storage and promoting innovation in storage by placing it under the CfD regime rather than the capacity regime.
Professor Walker: A broader point that I would make in terms of cost effectiveness is to always remember that the most cost-effective thing is to achieve the same outcomes but without using energy at all in the first place. I would talk there, for example, about cooling without air conditioning. That is something we have been very good at for a long time in this country, but air conditioning is increasingly moving into not just office environments but a lot of other non-domestic settings, and there is a big concern that air conditioning could be moving into the domestic world as well. That is an entirely new form of energy consumption that we do not necessarily need at all because there are many ways of achieving cooling without air conditioning. It is one of the social dynamics that we are interested in investigating and trying to understand. Why is air conditioning moving through the UK
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building stock in the way it is, introducing new demands for electricity on the system? Natural lighting, only using heating and lighting when we need to use heating and lighting and all those sorts of things should not be forgotten in all of this. It is easy to talk about the smart technology and the complicated stuff when sometimes some of the simple stuff is the most cost effective and the most important.
Q120 Lord Broers: Could I ask another simple question, triggered by Dr Porter talking about different time zones? Will the smart meter allow complete flexibility in that? It strikes me that the easiest way to get rid of this 5 pm to 7 pm hump would be to price that highly. If you had a dynamic pricing structure over the 24 hours easily in force then I would have thought you could bring the market to bear on bringing that peak down straight away—charge three times as much between 5 pm and 7 pm.
Professor Walker: The big question is: what can realistically be moved out of that time period? What is flexible in that evening peak? We have been doing work on this looking at time-use diary data, looking at how people are using their time. What is going on within the peak period? How is that locked into other things that people are doing like working hours and school hours? The evening period in the domestic setting is often a very intense frantic period with lots of activity going on and if you are pushing prices up very significantly during that period, all you could be doing is penalising consumers who cannot necessarily just reposition stuff. The question about what is flexible and what is not flexible in this is important and it is not sufficiently understood as yet. We are starting to get some indication from some of the early trials with smart meters and various things, but I think there is a real lack of detailed understanding about how electricity is being used at all and, therefore, if we do not know that then we do not necessarily know how much of that is moveable and whether you are just going to—
Lord Broers: That is probably a very good thing. I am sure Lord Winston would confirm that it is a bad thing to have a great big meal in the evening. One would have one’s meal in the middle of the day.
Professor Walker: We have been thinking about the changing social patterns of both eating in and eating out and how that has shifted over time, because there have been big shifts over time. It could be that the nature of what goes on in that evening peak does move, certainly it is in terms of patterns of TV watching and the use of computers, mobile phones and tablets. That is all very much a dynamic area of activity in the home environment with implications for electricity consumption during that period.
Dr Porter: I would agree with all of that. However, one has to think: within a domestic building—I am talking about the domestic environment not the commercial, although the same applies there—where are the big electricity users? It is not the power for your TV, because that uses a lot less than it used to do.
Professor Walker: It depends how many you have on.
Dr Porter: Clearly, if you have 10, that is not useful. The big users are: heating hot water, if you have it; electric heating, if you have that; cooking; and your major white goods. A lot of those require a lot less than they used to because of various European regulations, which we have all signed up to, to reduce the usage of those individual appliances, which is a good thing. I agree with my colleague Gordon that only some things can be switched. However,
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washing machines, dishwashers, cold appliances, electric heating and electric hot water are all pretty high-level things that are switchable to an extent.
I always give the example of a dishwasher. There is no reason, in most households, why the dishwasher has to be turned on at 10.30 pm when you go to bed—it is half full, but you put it on—whereas it could be done at a different time. You could press the button and the smart system decides. You say, “I want the dishes clean by 7.30 the following morning”, or whatever it is. The system then turns that on when there is available energy: when it is cheap, low carbon, whatever the issue is. That involves the use of a relatively dumb technology. It is technology, but it is not rocket science. That is relatively straightforward. That brings us back to Lord Wade’s discussion about the consumer having the power—the consumer says, “Oh, forget this. I am going to use it now”, but the incentive is: turn it on.
Lord Rees of Ludlow: Following up on the social science, I would like you to put your crystal ball on and think beyond 2020 and I would like to ask you in particular about some official future scenarios done by DECC and Ofgem. Do you think they cover the full range of potential changes that may happen? Also, what do you think about future technologies and the impact they would have on these issues?
Professor Walker: We have started to talk to DECC and Ofgem about how good their scenario work is, particularly in thinking about social futures. They are very good at dealing with the variables they feel comfortable with, like technological efficiencies and different scenarios for making technologies more efficient or with population growth or economic growth—the big macro questions. However, if we went into, “Well, what is the future of lighting at home? What is the future of cooking? What is the future of all sorts of different ways in which energy is used”, their scenarios get very basic, if they deal with any of those questions at all. They had a review done recently of all their energy system models, which concluded that there was very little effort going into the modelling of social processes. We think there would be ways of going into those.
It is very difficult to know with any degree of certainty about processes of social change. I think they are far harder to deal with than others in many ways. On the other hand though, you could work through: what are the possible different scenarios for cooking? The way people cook, the way they prepare food, the balance between cooking at home and eating out—all these sorts of things would be relevant to the peak and you could develop scenarios that built up from a range of different key forms of energy use to inform some of the modelling they did in a better way.
Michael Ware: I think the difficulty is that consumer behaviour changes much more quickly than the Government can react by changing generating capacity. Consumer behaviour can conceivably change very quickly within the next five years. It is almost impossible to get any significant generating capacity in place within such a short timescale. I suspect the whole focus of demand-side response on the consumer, and it may be a bit of a cul-de-sac, is that from an investment point of view it is very hard to rely upon consumers. The demand-side aggregator is unlikely to have a contract with every single consumer. If it did have a contract with every single consumer, it would be very expensive to enforce. If people do not behave in a way that the demand-side aggregator anticipated, it is very difficult, apart from crude pricing mechanisms, to influence that behaviour.
I suspect the easier contractual situation is to focus on the commercial and industrial sectors because there is a smaller number of users, there is a contract in place and it is an
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enforceable contract. I would rather have one contract with Sainsbury’s than 10,000 individual consumers because I can enforce that and I can make an investment decision on the basis of my contract with Sainsbury’s. I can go back to the grid and say, “I can guarantee to deliver you X amount of capacity between peak hours”. It is much harder for a DSR aggregator to make that assumption and assertion based on 10,000 individual consumers who may change their behaviour very quickly in the next five years.
Just to summarise that point, I think the focus of demand-side response is it is too difficult to rely upon consumers. They do not adhere to contracts and their behaviour is very unpredictable. Corporates are much easier as an investment proposition.
Q121 Lord Rees of Ludlow: Professor Walker, do you think that social attitudes may change so that, apart from the financial incentive, there may be a feeling that it is somehow naff to be extravagant with energy—a change in attitude like we have had in smoking and drink-driving and issues like that—and that may also have an effect on individual behaviour?
Professor Walker: That is certainly talked about. The degree to which we are likely to see change in how energy is used because of a change in the way of thinking about things is a bit limited. People are caught up in all sorts of habits and routines and ways of doing things with other people in patterns of everyday life, which means that, even if you become very environmentally aware or very concerned about energy, it does not necessarily mean you can unpick all the ways you are using energy. People certainly talk about smart meters and other forms of technology as creating a different relationship between people and energy. We are a little sceptical in our approach to this, but certainly that is talked about.
Dr Porter: From an investment perspective I entirely agree with my colleague, but maybe to get domestic demand-side management to work you probably do not use the same methodology. You do not use the aggregators for Sainsbury’s as you do for 10,000 householders. It is not the right model. If we want to get demand-side management to work with 25 million households with smart metering infrastructure in place in a few years’ time, I do not think the model—as Michael would be very aware of—is the right one, for the reasons he has explained. There would need to be a different relationship, maybe through the energy company, but it needs some thinking as to how exactly that would work commercially because, I agree, I do not think it would work commercially with the current arrangements.
Lord Dixon-Smith: Chairman, I may get my head chopped off but we are worrying about the peaks. What I am concerned about is how we fill the troughs because that is where we are going to get spare capacity to deal with the complete electrification of road transport, which is the long-term prospect if we are going to achieve the 2050 target. It will not be batteries, in my view, but fuel sales and hydrogen that run it. I wonder what we are going to do with all the redundant batteries when their lives eventually run out, whereas hydrogen has a benign cycle. You turn water into hydrogen and oxygen and you reverse the process and get the electricity back. What I worry about in the long term is not the peaks. The peaks will take care of themselves just simply because costs will be something that everybody will work on, including residential customers, and we see a constant improvement in the efficiency of domestic equipment. The demand-side management is going to be the critical thing and it will be essential that the generating industry can handle virtually a flat line, probably, in electricity production and it may even have to expand as a result of the changes that are going to come about. Having a discussion, which is what we have been having, is fine, but we
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are not constantly, nationally, thinking about the target that we have set in legislation and that is behind all this. The first thing we shall have to do is fill up the troughs. We will not need that much additional generating capacity if that is what we do, but if we do not manage it with that in mind there will be problems even for the Treasury in this because the first thing they have to look forward to is losing a few hundred million of fuel duty and so on. We are not looking at this in a sufficiently long-term way and I hope you agree that these are manageable problems if we look at it in that way.
The Chairman: Dr Porter, would you like to take that one?
Dr Porter: Yes. I think you are absolutely right. Again, if you have a chance, look at the video that the clerk sent round to you, which is a demo of how we got 12 companies to work together to demonstrate how this could work. It was remarkable to see and remarkable we got them to work together. That is a real demonstration. The scenario demonstrated in Aberdeen at that conference was exactly in this area. If you simulate having a lot of wind power and you simulate having a sunny day on a roof based PV system, there were five ways in which you could store energy in that grid: from the bigger battery side, to putting it in a heating system, to putting it into an electric vehicle, in exactly the scenarios you are talking about. Even if you have very variable load and very variable usage in the future, if you can use a combination of smart technologies and the right financial systems that incentivises people, systems, energy companies to use a technology to smooth it, you will never get a perfect flat line but the benefit of adding more electrical use, although it increases the overall load, is that they are eminently switchable. As I mentioned earlier a lot of the things you use now are not very switchable, whereas if you have electric heating and electric vehicles those are eminently switchable. Therefore, you can manage the load much better, although the load is perhaps higher because you put more load on the network.
The Chairman: A final question from Lord Winston.
Q122 Lord Winston: It is just a short one. We have not discussed this, but we are hearing quite a lot about cybersecurity and whether or not smart meters increase our risk. What is being done about that?
Dr Porter: Again, I mentioned earlier there is an awful lot of work being done both on privacy and on security, but it has to be recognised that any system is potentially hackable. I am not a security IT expert, but even if you are Sony Films you can have a problem with this, as happened last week. Again, within the smart secure zone there has been an awful lot of work and focus on this to make sure that the utility-owned and offered equipment has the highest level of security for the functionality required.
There is a balance here. If you put too much security in, it puts the cost up and you do not do it. That is the German situation. The big problem is in putting so much security in there, which most people think is unnecessary, for certain functions, but there is an absolute requirement to have the security requirements done. An office of GCHQ has been involved in working with DECC to work out exactly the security requirements that have to go in all the equipment. From the individual smart metering side, it is felt there is a very low risk. There may be some risk that somebody could hack into your smart meter, but you have to ask why.
In terms of the overall cybersecurity, on whether you could shut the country down, the feeling from those experts is that is not the case. If you have a wider smart grid and you have the whole system to be smart, that is a much greater level of risk and there will be even
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more requirement to get it right. In terms of the smart meter rollout, everyone believes, including the security experts, that there is sufficient security put in place for the individual householder or, indeed, building and it does not cause a threat for the whole country.
Q123 The Chairman: We have just a final reference back to the smart meters again. You reminded us earlier that DECC have had to postpone by a month the rollout, but the date itself by which the project has to be delivered has remained the same. What needs to be done now in order to ensure that this programme is kept up?
Dr Porter: A lot of work has already been done. There is in the UK a great deal of co-operation between the different stakeholders and, compared to some of the European member states, we are doing it extremely well. I think we can all pat ourselves on the back a little bit. We are doing it very well. There are a lot of processes coming together. So, I think in the next few months we want as little change as possible.
The Chairman: No interference from Ministers.
Dr Porter: As little interference as possible from anybody. We know what everyone has to do to get over the line.
The Chairman: This is an election year.
Dr Porter: I am sitting in this place and I am well aware there is an election coming up, but all three major parties are fully behind the programme. That has been fairly consistent for the last 10 years and it is the case now. We are not expecting any major policy differential. There is a slight worry, if the fixed energy prices were to come in, what effect that would have on the usability of smart data in future. But, again, even if that were to come in, by the time the mass rollout comes, that policy, as I understand it, will have worked through before we come to the end. We are a little concerned about the talk of “Let us get rid of Ofgem”, given that Ofgem are getting more involved in the regulatory push to push utilities to roll out this technology. Even if there was a change in regulator, we would say that we should not take away the regulatory requirements that are in place because that could mean there is a dip in pushing the whole industry to deliver.
The Chairman: I must conclude the session. We have overrun, but I am most grateful for your patience in answering our questions. I certainly have taken away the message that you now want consistency of policy and we will see whether we can help deliver that. It is always an aspiration of this Committee to help. Thank you very much indeed. If there is any further information you feel you would like to impart to us as a result of this session, do please feel free to forward it to our clerk. Thank you again very much for your help.
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Durham Energy Institute, Durham University – Written evidence (REI0016) Authors: Dr Amy Wilson and Professor Michael Goldstein (Department of Mathematical Sciences and Durham Energy Institute) and Dr Chris Dent (School of Engineering and Computing Sciences and Durham Energy Institute). We are pleased to respond to the House of Lords consultation on “Resilience of Electricity Infrastructure”, based on our specialist expertise in energy systems modelling and broader statistical modelling methodology. This arises from work on the EPSRC funded project “Uncertainty analysis of hierarchical energy systems models: Models versus real energy systems” on which Amy Wilson is the research associate and Chris Dent and Michael Goldstein are the investigators (see below for outline of expertise). We would be pleased to discuss issues raised in this response with the committee if that would further aid the inquiry. Q: What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? Summary of response: Modelling can provide valuable evidence to support policy decisions, however it is essential that, if we are to draw robust conclusions about real-world issues based on modelling results, careful assessment of the relationship between the model and the real system is vital. Current models of future energy infrastructure often have a large number of inputs, many of which are uncertain. Examples include the Dynamic Dispatch Model (DDM), which is used to estimate the capacity to procure in 2018 for the new Capacity Market (National Grid, 2014), and the UK TIMES and MARKAL models which have been used to support a number of policy initiatives over the last decade (see www.iea-etsap.org and Kannan, 2007, for details). The DDM has as some of its inputs the annual and peak demand from 2014 to 2030; these inputs are uncertain and must be estimated. When a model has uncertain inputs, then the outputs are also uncertain, and it is important to quantify this uncertainty. The current approach used to analyse uncertainty in energy systems modelling focuses on estimating future outputs using the inputs from a variety of different scenarios. The change in output across the different scenarios might give some idea of how resilient the models are to changes in inputs (known as sensitivity analysis). Alternatively, different scenarios can be used to test how different decisions might affect future energy infrastructure. There are three main issues to consider when assessing the reliability of energy systems models: 1. Very few models have been tested against real observations. No model of future energy infrastructure will perfectly represent the true relationship between the inputs and the outputs of the model. Unless the model is validated against known historical inputs and outputs, the size of the discrepancy between the model and the real-world is not known. If
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no attempt is made to quantify the accuracy of the model with respect to the real-world then using the model to make statements about future energy infrastructure based on different scenarios may result in inaccurate outputs and predictions. 2. It is important to analyse the robustness of the outputs of models to different input choices. If the sensitivity of outputs to inputs is tested by varying one input at a time, and checking how much the output changes then any possible interactions between inputs are ignored. It might be the case that any change in output when two inputs are changed simultaneously is greater than the sum of the changes when the two inputs are changed separately. It is important to have a thorough understanding of the effect that changing inputs both separately and in groups has on the output of a model. This is because the precise values of the inputs are often uncertain, so if the value of the output changes drastically when the inputs are changed to values which are still reasonable, then the model outputs may be considered unreliable. Sensitivity analyses which consider interactions in this way are not always routinely performed for energy systems models. A further related issue is that testing the sensitivity of outputs to inputs one at a time using scenarios as described above has the disadvantage that no overall measure of the uncertainty in the output resulting from the uncertainty in the inputs can be obtained. Without such an overall measure, it is difficult to rely upon an output from a model for the purposes of making policy decisions. 3. There are limitations to using scenario-based analyses as described above. For complex models it can take a long time to run the model for a single set of inputs; using a small number of scenarios means that results can be obtained quickly. However, if the outputs of the model are only obtained for a small number of input scenarios, the full range of possible future outcomes is not explored. Methods exist to approximate models, so that the model response can be explored for a whole range of possible inputs in a short time (see the references given below for examples). Using these methods gives a more complete picture of the implications of different policy choices. There are well established statistical methodologies for performing uncertainty quantification for complex models which can resolve the problems discussed above (e.g. see www.mucm.ac.uk for information about the Managing Uncertainty in Computer Models (MUCM) project). These techniques have been widely applied in other settings, such as for climate models (Lee, 2013), oil reservoirs (Cumming, 2010) and models of galaxy formation (Vernon, 2010). In order to improve current models of future energy infrastructure, these statistical methodologies should be used to perform uncertainty quantification for these models, so that systematic and well justified conclusions which can aid in decision making can be drawn. Indeed, without such analysis of uncertainties, it is impossible to draw robust conclusions about real-world issues based on modelling evidence. 18 September 2014 References Cumming, J. A. and Goldstein M. (2010). Uncertainty Analysis for Oil Reservoirs. The Oxford Handbook of Applied Bayesian Analysis , 241-270.
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Kannan, R., Strachan, N., Pye, S., Anandarajah G. and Balta-Ozkan, N. (2007). UK MARKAL Model Documentation. Retrieved September 9, 2014 from www.ucl.ac.uk/energy-models/models/uk-markal Lee, L. P. et. al. (2013). The magnitude and causes of uncertainty in global model simulations of cloud condensation nuclei. Atmospheric Chemistry and Physics , 8879-8914. National Grid. (2014). Retrieved September 2, 2014, from http://www2.nationalgrid.com/UK/Our%20company/Electricity/Market%20Reform/Announcements/June%202014%20Auction%20Guidelines%20publication/ Vernon, I. G., Goldstein M. and Bower, R.G. (2010). Galaxy formation: a Bayesian uncertainty analysis. Bayesian Analysis 5, 619-670. Background of authors This response draws on previous experience of Dr. Dent in energy systems modelling (particularly involvement in the Electricity Capacity Assessment Study, and as incoming Chair of the IEEE Loss of Load Expectation Working Group which shares experience between utilities engaged in practical resource adequacy studies), and Prof. Goldstein within the EPSRC Managing Uncertainty in Complex Models project and other associated research on the relationship between computer models and real systems. Durham Energy Institute Durham Energy Institute (DEI) supports and produces cutting-edge research that tackles the societal aspects of energy technology through a unique interdisciplinary “Science and Society” approach. The institute draws on the expertise of world-leading researchers across Durham University with a membership spanning departments in science, social science and humanities. DEI researchers address a wide spectrum of energy issues such as renewable generation (wind, solar, hydro, bio) and integration, bio-fuels, carbon capture and storage, shale fracturing, smart grids and networks, low carbon transitions, energy risk, and energy for development. School of Engineering and Computing Sciences The work of the School of Engineering and Computing Sciences is organised through five Research Groups: Algorithms and Complexity, Innovative Computing, Mechanics, Electronics and Energy. As a small to medium sized School, it focuses its research in order to achieve recognition for international excellence in selected areas. In the 2008 UK Research Assessment Exercise all of its Engineering research output was assessed as being of of International Quality and over 70% was recognised as Internationally Excellent or World Leading (3* and 4*). The School was particularly praised for its research impact and the panel singled out its excellent research support and training arrangements. Statistics and Probability Group (Department of Mathematical Sciences) The Statistics Group at Durham University has an excellent track record in uncertainty modelling and uncertainty analysis. The group covers a wide range of topics associated with statistics and probability, including risk analysis, complex systems, decision making, non-
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parametric predictive inference, Bayes linear modelling, simulation, dimension reduction, and mathematical finance. Applications include environmental problems such as food safety and land use, energy systems such as electrical networks, storage and renewable resources, galaxy formation, software testing, systems biology, survival analysis, among many more.
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E.ON UK, EDF Energy and OVO Energy – Oral evidence (QQ 29-43) Transcript to be found under the OVO Energy
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E3C Electricity Task Group (ETG) – Written evidence (REI0033) Introduction 1. By way of background the Energy Emergencies Executive (E3) has been established since the summer of 200545 with representation from DECC, Ofgem and the GB electricity System Operator, National Grid. 2. The detailed emergency planning activities of E3 are undertaken by the joint industry and government emergency planning body, the Energy Emergencies Executive Committee (E3C) which reports to E3. This body consists of experts drawn from a wide cross section of stakeholders representing the gas and electricity industries as well as Government, devolved administrations, agencies, regulators, Trade Associations and Industry Bodies. 3. The Electricity Task Group (ETG) which I chair reports into E3C on emergency planning activities related specifically to electricity. Membership is drawn from the lead Government department (DECC), the regulator (Ofgem), network operators (DNOs at distribution level and the System Operator at transmission level) generators and suppliers46. 4. The ETG is the only body in GB which brings together representatives of the electricity industry, the regulatory authority(s) and the lead Government department to consider and prepare for events which may impact on the resilience of the electricity infrastructure. As such the ETG is very familiar with the issue of the resilience of the GB electricity infrastructure. 5. The ETG and its predecessor group47, has been in existence since the turn of the century. Questions 6. The ETG has reviewed the list of questions set out in paragraph 12 of the ‘Call for Evidence’. Many of these questions are not ones that directly pertain to the work of the group. However, a number are and it is these that this submission seeks to address. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’? 7. The ETG has, over many years, developed a series of measures to improve the resilience of the GB electricity system that extend to 2020 and beyond. 8. Examples of the type of work undertaken in the past ten years or so includes (i) development of a ‘Strategic Spares’ policy for GB network operators, (ii) improving the 45 E3/E3C was formed out of the Gas & Electricity Industry Emergency Committee which was formed in late 2003. 46 The Supplier position is currently unfilled. 47 The Electricity Supply Emergency Code Review Panel, which existed pre 2000.
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resilience of network sub stations to a ‘black start’ type event and (iii) facilitating the identification of GB power stations with potentially increased vulnerability in the event of a ‘space weather’ type event. 9. In addition to this work it should also be noted that the ETG spends a considerable amount of its time preparing for what happens if the lights do go out. Whilst all stakeholders work to ‘keep the lights on’ it is also important that plans are in place to deal with circumstances whereby the light are off and we need to ‘put the lights on’ and keep them on. 10. By way of example, the ETG has been actively involved with DECC (and its predecessor departments – DTI and BERR) in undertaking three reviews of the Electricity Supply Emergency Code (ESEC) and preparing for its possible activation ‘in anger’. 11. The ESEC was established at the time of privatisation. The code describes the steps which the lead Government department (DECC) can take to deal with an electricity supply emergency of the kind envisaged under section 96(7) of the Electricity Act 1989 or section 3(1) (b) of the Energy Act 1976, such as long-term damage to the system or prolonged shortfalls in generation. The code also sets out the actions that are required to be taken by companies in the electricity industry to deal with such an emergency and it is this aspect, in particular, that ETG has, over many years, worked on. 12. Thus the ETG has worked to ensure that enhanced communication mechanisms are in place to permit consumers in GB to quickly obtain the information they will need in the event that the code is utilised. These communication mechanisms have been in place for over five years and include (i) a website capable of (a) quick activation and (b) handling large volumes of ‘hits’; (ii) a mobile phone interactive texting service that allows consumers to text in their postcode and receive back their block letter; (iii) ensuring that block letter information appears on all customer bills; and (iv) a pre-prepared protocol for the activation of the arrangements. 13. In addition to this ETG has, over many years, worked with the lead Government department to exercise the activation of the ESEC arrangements by network operators. 14. This co-operation and support given by the ETG to the lead Government department has not been just confined to network operators. The ETG has also supported their work over many years in reviewing and enhancing the Fuel Security Code arrangements which relates, predominately, to GB generators. 15. The ETG has also, particularly since the summer of 200348, been mindful of overseas events that have affected the resilience of the electricity infrastructure. These have included major disruptions of a more technical nature; such as black start events; or those that naturally occur; such as severe weather events like storms and hurricanes. 16. This work, of post event consideration of lesions learnt / improvements etc., has not just been confined to overseas events, but has included events closer to home. For example 48 When the North Eastern US / Canada and Italy both experienced black start events.
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during the course of 2014 the group’s main focus of work has been discharging four actions that arose from the (DECC) Secretary of State’s Review of the Christmas 2013 storms. 17. This post event consideration has not been limited to just examining events that have occurred but also taking other steps to enhance the resilience of the GB electricity infrastructure. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? 18. The ETG has, over the years, identified a number of measures that would enhance the resilience of the GB electricity system. These have included an enhanced level of strategic spares for network operators and the development of a greater level of (time) resilience at certain sub stations in order to deal with a black start event. The group has identified the need for resilience enhancement and then this has been taken forward, as appropriate, by network operators with Ofgem as part of their regulatory price control regime. 19. In the case of the enhanced level of strategic spares for network operators this work included valuable contributions by the lead Government department (DECC) and the Security Services. 20. Having identified the broad benefits of these resilience enhancements then the cost(s) of individual enhancements by individual (and collective) network operators was left to them and the regulatory authority (namely Ofgem). Conclusions 21. The Electricity Task Group hopes that the above information gives reassurance to the Select Committee that notwithstanding the work that the committee will receive information on, from other parties, with respect to the ‘Resilience of Electricity Infrastructure’ from this Call for Evidence that if the worst comes to the worst that plans are in place (and kept under review) to deal with events which could affect electricity supplies in GB. 19 September 2014
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EDF Energy – Written evidence (REI0030) Key Messages
EDF Energy believes that the country needs energy infrastructure fit for the 21st century and the urgent challenge now is to secure the vital investment that will ensure there is adequate capacity to meet future electricity demand. This is combined with the need to reduce emissions at least cost to customers. The Government is leading the way in setting the market framework for reducing greenhouse gas emissions, and we must ensure that the momentum needed to make the transition to a low carbon economy is maintained.
EDF Energy has been working with the Government, the regulator and industry stakeholders to implement significant reforms that will have long-lasting effects on the structure of the market to bring benefits to customers. These include the Government’s Electricity Market Reform (EMR) programme.
About EDF Energy 1. EDF Energy is one of the UK’s largest energy companies with activities throughout the
energy chain. We provide 50% of the UK’s low carbon generation. Our interests include nuclear, coal and gas-fired electricity generation, renewables, and energy supply to end users. We have over five million electricity and gas customer accounts in the UK, including both residential and business users.
2. We are making substantial investments in electricity generation in the UK. Earlier this
year, we opened the new 1.3GW West Burton B CCGT plant and the 62MW Teesside offshore wind farm. We are preparing to build a new 3.2GW nuclear power station at Hinkley Point C in Somerset and we also continue to develop new wind generation. We are investing to extend the lives of our existing 15 nuclear reactors so they can safely continue to produce low carbon electricity and to keep our two coal-fired power stations in operation into the 2020s.
Short term (to 2020) How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base?
3. The resilience of the system is maintained by a set of market and system operation
arrangements to ensure that demand is balanced with generation at all times. Generators are incentivised through energy and balancing markets to generate when needed. The System Operator is well prepared to handle sudden system shocks, for example sudden pickup in demand, or a power station failing to generate due to an unforeseen outage. Historical evidence shows that the system is very resilient to peaks in consumer demand.
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4. The current arrangements continue to work well, but we recognise that there will be increasing challenges as the generation mix changes with an increasing proportion of intermittent renewable generation. In addition, the proportion of distributed generation is also increasing; this is not centrally despatched by the System Operator and there is less visibility of its operation.
5. As part of the Electricity Market Reform measures in the Energy Act 2013, the Government has defined the required level of security of supply in terms of a Reliability Standard expressed as a Loss of Load Expectation (LOLE), currently set at 3 hours per year. This does not mean 3 hours of blackouts per year; it means that, on average, there may be 3 hours per year when supply would not match demand and exceptional measures would be required to avoid significant impacts on customers. We believe that this strikes a sensible balance between the costs and benefits of increased security of supply and is comparable with standards in neighbouring countries.
6. The underpinning evidence base for assessing the margins associated with loss of
generation load has been assessed annually by Ofgem49. The assessment is based on data from National Grid accompanied by analysis undertaken by Ofgem and DECC.
What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’?
Capacity Market
7. The Capacity Market (CM) is currently being implemented as part of the Government’s Electricity Market Reform programme. It has been introduced to mitigate the risk that an energy-only market fails to ensure sufficient capacity to ensure security of supply. We support the Capacity Market as a technology neutral mechanism that should bring forward the most economic sources of capacity: from new and existing generation, from baseload, mid-merit and peaking capacity and from other sources such as demand side response, storage and interconnection.
8. EDF Energy believes that the extensive process leading to the implementation of EMR has delivered a coherent package of measures and we expect that, if implemented as planned, these measures, including the Capacity Market, will succeed in their objectives.
Interim Measures
9. DECC, Ofgem and National Grid are undertaking a number of policy and regulatory measures to improve the resilience of the system ahead of the start of the first Capacity Market delivery period in 2018, particularly in light of tightening capacity margins over the forthcoming winters, as identified in Ofgem’s last two capacity assessment reports50.
49 Ofgem Electricity Capacity Assessment 2014 https://www.ofgem.gov.uk/publications-and-updates/electricity-capacity-assessment-2014. 50 Ofgem Capacity Assessment 2013: https://www.ofgem.gov.uk/ofgem-publications/75232/electricity-capacity-assessment-report-2013.pdf and Ofgem Capacity Assessment 2014:
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National Grid has introduced additional mechanisms, Supplemental Balancing Reserve (SBR) and Demand Side Balancing Reserve (DSBR) on the supply side and demand side respectively, to ensure sufficient capacity is available for a secure system. We believe that these measures can make an important contribution to maintaining security of supply in the short term but they will not bring forward the investment needed to ensure security of supply over the longer term. Winter 2014/15
10. Particular concern has been expressed over the security of supply outlook for the coming winter. National Grid published an open letter in September51, referring to a number of developments. These include fires at the Ironbridge (E.ON) and Ferrybridge (SSE) power stations and a closure announcement regarding the power station at Barking (Barking Power Ltd) as well as the temporary shut down of EDF Energy’s Hartlepool and Heysham 1 stations.
11. On August 11, EDF Energy reported that the four nuclear reactors at its Heysham 1 and
Hartlepool power stations would be shut down to allow a detailed programme of boiler inspections to take place. This precautionary measure was taken after the discovery of a crack on a component known as a boiler spine at Heysham 1. Hartlepool power station was also shut down because both stations share the same unique design. EDF Energy expects to bring these reactors back into service between the end of October and the end of December, 2014 and will give further updates when it is able to do so.
12. As a result of the increased level of uncertainly over the volume of plant that may be
available in the market this winter, National Grid has taken the precautionary step of seeking additional tenders for SBR for this winter and will then decide in the light of developments whether to accept any such tenders.
Interconnection
13. Interconnection between the GB and other countries can help to contribute to the resilience of our electricity system. There are currently four interconnectors providing connections to Ireland, France and the Netherlands with a combined import capacity of 4.3GW. As a result of price differentials, the Irish Interconnectors predominantly export from UK to Ireland, whereas the French and Dutch interconnectors import to the UK leading to a net average transfer to the UK of 1.5GW during 2013. There are proposed plans for further interconnectors up to a potential capacity of 7GW, although most of these are unlikely to be built until the 2020s.
14. However, interconnection will only help to contribute to security of supply if there is
spare capacity in neighbouring countries when it is needed. As the level of interconnection between GB and neighbouring systems grows, it will be increasingly
https://www.ofgem.gov.uk/ofgem-publications/88523/electricitycapacityassessment2014-fullreportfinalforpublication.pdf 51 National Grid Open Letter http://www.nationalgrid.com/uk/electricity/additionalmeasures.
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important to consider what would happen in the event of a stress event affecting a number of interconnected countries simultaneously.
Networks
15. EDF Energy believes that investment into the electricity grid and gas network is vital to support resilience, security of supply and connecting new generation. Up to 2020 there is expected to be significant new renewable generation which will need to be connected to either the distribution or transmission network. This will require a large amount of investment from the Network Operators which will be regulated by Ofgem. We believe a balance must be struck between improving resilience through reinforcement of current lines, new build to reduce congestion on the network and the cost to consumers. The effectiveness and efficiency of the processes governing funding and delivery of new transmission infrastructure should be monitored closely to ensure that needs cases are identified promptly and transparently.
Business Continuity
16. EDF Energy has implemented a company wide business continuity management framework to support the continuity of its operations during major unexpected events. This framework is underpinned by a Business Continuity Management Policy together with supporting guidance which is implemented across the company. Business continuity, emergency response, incident management, disaster recovery, cyber response and crisis management plans have been developed and implemented. These management plans are reviewed and tested on a regular basis.
17. EDF Energy supports and contributes to industry wide initiatives which enhance the
resilience of electricity infrastructure. Of particular relevance to electricity infrastructure responses to unexpected events is the Government sponsored Energy Emergency Executive Committee (E3C). This group has supported initiatives such as the energy sector responses to pandemic, security and cyber threats.
18. EDF Energy’s new nuclear power stations are being designed with security as a primary
consideration. Resilience against external events such as severe weather and cyber attacks are taken extremely seriously and plans are scrutinised by the independent regulatory bodies such as the Office for Nuclear Regulation.
How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? 19. The costs and benefits of investing in resilience are determined by a mix of the market
and a framework set by Government or the regulator. For instance, investment in network resilience is regulated by Ofgem, whereas for generation capacity adequacy the level of resilience is set by Government but delivered competitively by the market.
20. Implicit in the Reliability Standard of 3 hours Loss of Load Expectation per year set by Government is an estimate of the Value of Lost Load (VOLL). VOLL is the price that
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customers would be willing to pay to avoid losing electricity supply. In practice, of course, this price varies between different customers and between different times; nevertheless, it provides a useful guide to determine how much money should be spent to deliver security of supply. The key decision is taken by the Secretary of State in setting the parameters, including the auction price cap, for the Capacity Market,
What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? 21. The urgent challenge now is to secure the vital investment that will ensure there is
adequate capacity to meet future electricity needs while reducing emissions at least cost to customers. We believe that existing policies, including the implementation of Electricity Market Reform, provide the basis for ensuring that the UK’s electricity system is resilient, affordable and on the right trajectory to decarbonisation.
22. EMR has been subject to prolonged and detailed consultation (since the white paper in
2010) with input from numerous stakeholders, and has a strong democratic mandate having been voted through Parliament as part of the Energy Act 2013.
23. However, there are further key decisions that need to be taken in the next few years that
will shape the progress to be made during the 2020s. We have set these out in our answer below on the steps required to deliver an electricity system that is resilient, competitively priced and decarbonised by 2030.
Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure?
24. It is important that the Government, together with the electricity industry, continues to
monitor key developments, to check that policies remain effective and to review the potential implications of developments in technology.
Medium term (to 2030) What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
25. EDF Energy recognises that the changing nature of the generation mix (including the
growth of intermittent and/or distributed generation) and changing patterns of customer demand are likely to lead to new challenges to the resilience of the UK’s electricity infrastructure. We believe that it is important that the industry continues to monitor such trends and continues to adapt the design and operation of the electricity infrastructure to deal with such challenges.
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What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? 26. EDF Energy operates in an environment that is constantly changing where there are a
multitude of future scenarios. Therefore we use a scenario-based modelling approach to tackle and understand uncertainties within our market place and to aid our decision making process. There are a wide range of variables and our decisions cannot be made based entirely based on historical data, but can be supported by trends. Scenario based modelling tools are designed to support decision makers tackle problems and to design strategies that are resilient to the challenges of an unpredictable world. Scenarios need to be coherent, credible and contrasted in order to add value to understanding risk and uncertainty. National Grid52 and the Department for Energy and Climate Change (DECC53) use similar modelling techniques to EDF Energy to aid their decision making process. We believe that this approach allows us and other stakeholders to understand the risks and to become more resilient.
What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? 27. The Energy Act 2013 provides for a target for the carbon intensity of electricity
generation in 2030 to be set in 2016. This is a critical policy decision for the next Government which will have a key influence on subsequent decisions.
28. EDF Energy believes that Electricity Market Reform provides a coherent package of
solutions to a number of market failures and provides a framework for the affordable delivery of decarbonisation of the electricity system while maintaining a defined security of electricity supply.
29. We need a robust carbon price that reflects the impacts of climate change and drives market behaviours towards a low carbon economy. This requires reform of the EU ETS, which the UK Government should continue to press for within the EU’s decision-making bodies; however, we recognise that this will take time to deliver.
30. The Carbon Price Floor (CPF) helps to provide a level playing field for low carbon
generation in the UK by taxing generators to reflect the costs of the carbon emissions that they cause. This leads to reductions in carbon emissions in the short run by encouraging a switch from coal to gas generation and in the longer run by promoting investment in low carbon generation.
31. The carbon price floor trajectory beyond 2020 will be reviewed in due course in the light
of reforms to the EU ETS. The Chancellor’s announcement of a freeze in the level of carbon price support included a commitment to the CPF as a means to stimulate
52 National Grid – http://www2.nationalgrid.com/uk/industry-information/future-of-energy/future-energy-scenarios/. 53 DECC – https://www.gov.uk/government/collections/energy-and-emissions-projections.
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investment in low carbon energy. EDF Energy welcomes the continuing support for this stable and long term approach and the role of carbon based taxation. We also recognise that Government is striving to seek a balance between pricing carbon costs into the market and ensuring that the UK remains competitive and that energy prices remain affordable.
Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? 32. To a large extent, the generation technologies needed to ensure that the UK’s electricity
system is resilient are already available. However, some low carbon generation technologies will require further development to make them commercially viable and/or to reduce the level of support that they will need. Others are at the pre-commercial stage and can be delivered on a small scale and some are at the Research and Development stage.
33. Electricity storage could potentially be a game changing technology for the industry if it
were developed to the point where very large volumes of energy could be stored at a commercially viable cost; this would provide a means of managing some of the challenges associated with intermittency. However, this development does not appear likely in the short or medium term. Large pumped hydro schemes exist, but none have been built in recent years. The introduction of the capacity mechanism may incentivise any remaining potential sites to come forward for investment.
Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system? 34. In the longer term, EDF Energy believes that all low carbon technologies should
participate fully in the market and compete on cost on an equal basis, underpinned by a robust carbon price.
Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects? 35. A particularly effective, existing, way for Government and industry to learn from the
outputs of research and development is to maintain close links with the Energy Technology Institute (ETI). The ETI is a public-private partnership between global energy and engineering companies and the UK Government. Their role is to act as a conduit between academia, industry and the government to accelerate the development of low carbon technologies. The ETI brings together engineering projects that develop affordable, secure and sustainable technologies to help the UK address its long term emissions reductions targets as well as delivering nearer term benefits. The ETI make targeted commercial investments in technology programmes across heat, power, transport and the infrastructure that links them.
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Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? 36. EDF Energy believes that regulatory and policy context in the UK is enabling. We also
believe that coordination between all of the relevant bodies is important to set the right framework. Stability in this framework is necessary to provide investors with the confidence to invest. Electricity Market Reform should set the right framework for the market to invest in the electricity infrastructure required to deliver resilience.
19 September 2014
EDF Energy, OVO Energy and E.ON UK – Oral evidence (QQ 29-43)
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EDF Energy, OVO Energy and E.ON UK – Oral evidence (QQ 29-43) Transcript to be found under the OVO Energy
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EDF Energy –Supplementary written evidence (REI0053) Follow-up questions to Paul Spence following an evidence session on 28 October 2014
1. The difference in electricity capacity margins between France and the UK, currently and projected for the coming winter.
It is not wholly straight-forward to compare electricity capacity margins in France and Great Britain directly in terms of the percentage by which installed generation capacity exceeds peak demand. This is because the peak demand in France is extremely sensitive to cold weather, rising from 85.0 GW at reference temperature conditions to 101.3 GW under the 1-in-10 cold winter conditions. For this reason, France has always used a probabilistic calculation to determine the chance of a supply shortfall, expressed in terms of the loss of load expectation, i.e. the number of hours each year, on average, when demand is expected to exceed supply. Since 2012, Ofgem has used a similar metric to assess the reliability of supply in Great Britain, and the comparison below for the coming winter and subsequent winters is therefore made using this metric. These projections of generation system adequacy made by the transmission system operator, RTE, for France, and the regulator, Ofgem, for Great Britain, show that the two countries enjoy similarly reliable electricity systems. The magnitude of the supply shortfall (expected energy unserved) is also shown, together with the surplus or deficit of capacity compared with what is required to deliver the 3 hour loss of load expectation reliability standard (where available). FRANCE
2014/15 2015/16 2016/17 2017/18 2018/19
Expected energy unserved 3.3 GWh 15 GWh 23 GWh 14 GWh 9 GWh
Loss of load expectation 1h 4h 5h45 4h 2h30
Surplus or deficit of capacity 2,900 MW -900 MW -2,000 MW
-800 MW 500 MW
Source: RTE, Bilan Prévisionnel de l’équilibre offre-demande d’électricité en France, Édition 2014, p. 115 (Scénario Référence) http://clients.rte-france.com/htm/fr/mediatheque//telecharge/bilan_complet_2014.pdf GREAT BRITAIN
2014/15 2015/16 2016/17 2017/18 2018/19
Expected energy unserved 0.5 GWh 4.2 GWh 0.8 GWh 0.3 GWh 1.9 GWh
Loss of load expectation 0.6h 3.8h 0.9h 0.3h 1.8h
Surplus or deficit of capacity 1,659 MW -224 MW 1,225 MW 2,103 MW 465 MW
Source: Ofgem, Electricity Capacity Assessment Report 2014, 30 June 2014, pp. 46-47 (Gone Green scenario) https://www.ofgem.gov.uk/ofgem-publications/88523/electricitycapacityassessment2014-fullreportfinalforpublication.pdf
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It is important to emphasise that the same capacity margin on either side of the channel would deliver a very different security of supply standard due to the very significant differences in the generation mix, and especially in the thermosensitivity of demand. Therefore looking at the capacity margin is less useful than the loss of load expectation in terms of comparing the relative reliability of the two systems.
2. The difference in electricity prices between France and the UK.
15 December 2014
The Electricity Storage Network – Written evidence (REI0012)
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The Electricity Storage Network – Written evidence (REI0012) 1. The Electricity Storage Network is the UK’s industry association for the promotion of
electrical energy storage. Current members include electricity storage manufacturers and suppliers, developers of electricity storage projects, users, electricity network operators, consultants, academic institutions and research organisations.
2. The Electricity Storage Network works on behalf of its members to respond to and
address issues affecting the development and utilisation of electricity storage within the UK power system. This includes special interest meetings, liaising with the media, responding to consultations, providing a unified point of contact for those interested in electricity storage and promoting the value of storage within the UK power system.
Select Committee on Science and Technology – Questions Short term (to 2020) 3. How resilient is the UK’s electricity system to peaks in consumer demand and sudden
shocks? How well developed is the underpinning evidence base? 4. Britain is facing a power capacity crunch as ageing and polluting stations are
decommissioned as the UK shifts to low carbon but intermittent sources of renewable generation.
5. Recent fires at E.ON's biomass-fuelled Ironbridge plant in Shropshire and SSE's
Ferrybridge plant in Yorkshire, has forced generators to reduce output; while a power plant in Barking, east London is set to close and there have been production problems at EDF Energy's Heysham and Hartlepool nuclear power stations.
6. Last year, the industry regulator Ofgem warned that spare generating capacity in the UK
could fall to 2% by 2015. In order to address capacity issues new markets and services have been introduced, but are likely to be high carbon in nature.
7. What measures are being taken to improve the resilience of the UK’s electricity system
until 2020? Will this be sufficient to ‘keep the lights on’ 8. If the UK is to increase the resilience of the electricity network, improve its flexibility, and
firm up the security of supply of electricity, then more needs to be done to support solutions like electricity storage, which can offer a multitude of services to the grid. Electricity storage also has the benefit of being low carbon and can support greater penetration of intermittent and inflexible generation.
9. The Department of Energy and Climate Change (DECC) and Office of Gas and Electricity
Markets (Ofgem), have supported some electricity storage demonstration projects in the UK, however if storage is to support the grid going forward and be rolled out by industry
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extensively, then more needs to done by government to open up and support the electricity storage market.
10. How are the costs and benefits of investing in electricity resilience assessed and how
are decisions made? 11. Grid assets have historically been judged on capital costs, however traditional forms of
generation, though resilient, do not support the decarbonisation of the electricity grid. UK Government needs to not only support the lowest cost technologies but solutions that offer a portfolio of services that for example can support the grid during peaks times and maintain the deployment of renewables and that result in decarbonisation of the electricity system.
12. What steps need to be taken by 2020 to ensure that the UK’s electricity system is
resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
13. Imperial Colleague London have stated that by 2050, with increased levels of renewable
generation, applications of electricity storage technologies could potentially generate total system savings of £10bn/year. If electricity storage is to reach its full potential in the future, targets of 2GW for storage by 2020 need to be set now and UK Government needs to implement supporting mechanisms to help open up the market.
14. Will the next six years provide any insights which will help inform future decisions on
investment in electricity infrastructure? 15. Electricity storage is a here and now solution and its maturity will be further validated
over the next 12 months as a number of multi MW demonstration projects come online across the UK. The projects will exhibit electricity storage technologies operating with real world applications offering a range of flexible services.
16. A 2GW target of new storage on the UK grid by 2020 has been proposed by the
Electricity Storage Network (ESN) and is now agreed by industry and government. The ESN is in the process of reviewing appropriate supporting mechanism which will be proposed to government to help meet the targets.
Medium term (to 2030) 17. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will
new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
18. On the transmission system the loss of large-scale high carbon generation has already
reduced the resilience of the whole system to frequency events. The system operator is beginning to think about new services to improve resilience, but these are yet to be fully developed.
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19. At the local level the addition of heat pumps and electric vehicles will increase demand and heat pumps pose a particular problem for the distribution network on cold winter mornings when demand is high, but the wires can’t support that demand. During summer at midday PV generation peaks, but demand is low and the wires are not able to cope with the generation – this problem occurs now and electricity storage could provide resilience by supporting frequency and inertia (larger scale) and by allowing small-scale PV generation to be stored for later use during the evening demand peak, saving the customer money, by allowing them to “self-consume”
20. What does modelling tell us about how to achieve resilient, affordable and low carbon
electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models?
21. The electricity generation modelling undertaken by Imperial Collage London, found that
although scenarios with a high share or renewable generation are the most favourable for electricity storage, however even in scenarios with significant nuclear generation (inflexible), electricity storage has a role to play. Alternative technologies, such as flexible generation, demand side response or interconnection are found to reduce the value of electricity storage, but do not displace its role since electricity storage can offer multiple system-wide benefits.
22. What steps need to be taken to ensure that the UK’s electricity system is resilient as
well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
23. Some steps have already been taken (Capacity Market and Demand Side Balancing
Reserve/Supplemental Balancing Reserve) to improve resilience in the short term, however these solutions may not be cost-effective and are not low carbon.
24. Current policies do not support the development of low carbon, cost-effective resilience.
System operation is highly dependent on high carbon generation to provide balancing and the Transmission System Operator is not required to procure services that are low carbon, only low cost. More innovation at the transmission level is needed to develop the technologies that will provide the services of the future, such as inertia and frequency response, without resorting to high carbon providers.
25. Is the technology for achieving this market ready? How are further developments in
science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
26. Electricity storage is ready and available today. We do not need advances in the
technology but we do need advances in market conditions to encourage further deployment of storage technologies and to meet the 2GW target.
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27. The value of storage is already being discussed amongst parliamentary members and in the House of Lords: ‘The Government agree that technologies that can be used to help balance the supply and demand of electricity, such as energy storage systems and demand-side response and interconnection, are increasingly likely to be required.’ Baroness Verma, 31st July 2013.
28. Is UK industry in a position to lead in any, or all, technology areas, driving economic
growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
29. The UK has outlined “eight great technologies” which will help the UK grow and prosper
over the next decade. The government has highlighted electricity storage as one of these technologies as it has the potential for delivering massive benefits – in terms of savings on UK energy spend, environmental benefits, economic growth and in enabling UK business to exploit these technologies internationally. UK business are already active in electricity storage, but are not able to exploit their business in the UK due to prevailing unfavourable market conditions.
30. Are effective measures in place to enable Government and industry to learn from the
outputs of current research and development and demonstration projects? 31. There is a lot of repetition in funded electricity storage projects as a result of poor
learning. This is not helped by there not being a single person in Government who has responsibility for electricity storage – indeed there is no-one in Government responsible for electricity storage, unlike many other low carbon technologies, which have their own offices within DECC. This lack of coordination means that Government support for electricity storage demonstration projects and research is wasted, as there is no market support in the UK for electricity storage.
32. Is the current regulatory and policy context in the UK enabling? Will a market-led
approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
33. Current market conditions in the UK are holding back the widespread deployment of
electricity storage technologies. In other country such as the U.S., the value of storage technologies are being realized and Government has set mandates and provided tax reliefs to encourage the levels of storage to grow. In Germany there is an incentive for distributed storage associated with PV generation to manage network and allow microgenerators to avoid buying electricity at peak demand (maximize self-consumption by shifting midday peak in generation to provide energy in the evening).
17 September 2014
The Electricity Storage Network, National Grid and Professor Goran Strbac, Imperial College London – Oral evidence (QQ 102-113)
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The Electricity Storage Network, National Grid and Professor Goran Strbac, Imperial College London – Oral evidence (QQ 102-113)
Evidence Session No. 9 Heard in Public Questions 102 - 113
TUESDAY 2 DECEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Manningham-Buller Lord Peston Lord Rees of Ludlow Viscount Ridley Lord Sharp of Guildford Lord Wade of Chorlton Lord Winston
_____________________
Examination of Witnesses
Anthony Price, Director, Electricity Storage Network, Dr Charlotte Ramsay, Project Director for NSN Link, National Grid, and Professor Goran Strbac, Faculty of Engineering, Imperial College London
Q102 The Chairman: Welcome to this session of our inquiry into resilience in electricity. I have to warn you that the acoustics in this room are notoriously poor, and some of us are challenged a bit in hearing so if you could speak up that would be helpful. We are being recorded, so I am going to ask you, for the record, to formally introduce yourselves. If anyone would like to make an opening statement, do please feel free to do so.
Anthony Price: Thank you. My name is Anthony Price. I am the Director of the Electricity Storage Network, which is an industry group with members representing developers of electricity storage: project developers, users, consultants and academic institutions. Our intention is to create a favourable market for electricity storage in the UK, because we believe that user storage is in the national interest and also that a strong home base will support our industries as they seek to develop export markets. We have a strong track record in creating awareness of the importance of electricity storage in the industry. I should also point out that I am the founder of Swanbarton, which is a consultancy company that
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specialises in the commercial applications of electrical energy storage. We have worked for clients in the UK, Europe, America and Asia.
If I may, I can make a few comments about storage in order to set the scene.
The Chairman: Dr Ramsay?
Dr Ramsay: Good morning. I am Dr Charlotte Ramsay. I am Project Director for NSN Link, in National Grid. NSN Link is the proposed interconnector from the UK to Norway. In addition to that role, I am also the head of the Commercial and Regulatory Team in National Grid’s European Business Development Division. Just for clarity, I should explain that National Grid has a separate business development activity that exists separately from its regulated monopoly activity. So that is where I am based and where I work.
The Chairman: Thank you, and Professor Strbac?
Professor Strbac: Goran Strbac, professor working in energy systems, Imperial College. I specialise in development of new methods to assess value—in this context, the value of emerging technologies and the role of emerging technologies in supporting cost-effective transition to low carbon future. We have done a lot of work—my team has done lots of work—on quantifying the value of storage and interconnection for the Government and Regulators, both in the UK and in Europe, to inform the decision-making process among policymakers but also in industry.
Q103 The Chairman: Thank you very much. Perhaps I could start then by asking a rather general question. How great a role does electricity storage and interconnection currently play in balancing the electricity system? To what extent are we dependent on these technologies?
Anthony Price: Perhaps I may take that question first then, Chairman. Currently our electricity system contains about 3 gigawatts of electricity storage in Great Britain against a peak load of, say, around 70 gigawatts, and in Northern Ireland there is access to 300 megawatts of pumped storage in the Republic. By balancing the system, we mean both second-by-second maintenance of the system frequency and longer-term balancing of energy—for example, peak against off-peak. The use of electricity storage to provide second-by-second frequency regulation is well documented and National Grid do publish information on their balancing services. So, typically, frequency regulation requires about 1 gigawatt of plant and fast reserve typically about 500 megawatts or 600 megawatts. That provision could be met entirely by our current pumped hydro in GB. But it is also not explicit exactly how much of this is used at any particular time unless you start diving into the deep detail of the contract arrangements between the providers and the system operator. I am informed that our pumped storage is not fully utilised in this area, mainly because of the commercial arrangements.
The Chairman: Can you explain that? You say we have pumped storage and we do not use it.
Anthony Price: We do not use it for providing frequency or providing fast reserve in its entirety because the contracts between the storage providers and the system operator are not sufficiently favourable for that to take place.
The Chairman: That is very surprising.
Lord Broers: Can I ask why? What is unsatisfactory?
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Anthony Price: I am not a pumped storage operator but, as I understand it, they need to recover a certain amount of their costs and, therefore, they put in place contracts either through tendering or through legacy arrangements to provide their services to the system operator, and if other providers of the same services can do so more cheaply then the contract will go to other providers.
Lord Broers: So it is too expensive?
Anthony Price: It could be seen to be too expensive.
Lord Broers: But it is the cheapest of the storage techniques.
Anthony Price: Yes, for bulk storage pumped electricity storage is very low cost.
Viscount Ridley: So is it competing against back-up generators, spinning reserves or something like that?
Anthony Price: In terms of frequency it is competing against typically CCGTs that can operate in a flexible mode. We have seen a decline in ancillary services prices over the past five or six years, mainly due to the fact that CCGTs have lost some of their energy sales and have been recovering their costs by offering increased ancillary services, often at very low marginal rates.
Lord Winston: Could you remind us what the efficiency of this pumped storage is? I cannot remember.
Anthony Price: I understand that pumped hydro, say Dinorwig, is about 75%. Modern pumped storage is achieving efficiencies up into 80%, 81%, 82%, as more efficient pumps and turbines are brought on stream.
Viscount Ridley: How does that compare with battery storage and efficiencies?
Anthony Price: It is about the same, if you compare it with the AC to AC component. Many battery providers will tell you that their battery is 86% or even 90% efficient, but if you include the rest of the system then it brings it down to typically the 75% to 80% area.
Lord Dixon-Smith: I want to understand what the competition is with pumped storage. Perhaps you can tell us who is beating these people on contract price and possibly why.
Anthony Price: I wish I could, but the tenders are not open to me. I am just an industry observer.
Lord Dixon-Smith: Can you tell us who, even if you do not know what or why?
Anthony Price: The main owners and operators of CCGT plant, which are typically the big generating companies, are now playing a more active role in providing frequency services.
Lord Dixon-Smith: Effectively, they are providing their own insurance.
Q104 The Chairman: If we could go back to interconnectors so we can be clear about capacity there, there is a very modest amount coming from the Netherlands, and then we are exporting to Northern Ireland, if you call that exporting. We are interconnected to Northern Ireland from England, and then of course the largest is from France. What sort of spare capacity would you assess there is on the interconnector from France?
Dr Ramsay: I can tell you a bit about the French and the Dutch interconnectors, because they are the two that sit within National Grid’s portfolio. Of the 4 gigawatts of
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interconnection that we have, there are 2 gigawatts to France and 1 gigawatt to the Netherlands, and currently both of those interconnectors are providing balancing services in different forms, so the Dutch interconnector, BritNed, can provide frequency response services to the system operator, which I believe it does at quite competitive rates and is being used relatively regularly since we started offering that service. It can do this because it has particular technologies that allow it to offer this kind of service to the system operators. Not all interconnectors that are connecting into the UK can have this dynamic overload capability, so they cannot all offer this service but those that do can do it very competitively. For BritNed there are also system operator to system operator arrangements, which means that National Grid can communicate with TenneT at times of system emergency or close to system emergency, to have arrangements to help manage during difficult circumstances.
For IFA, the French interconnector, it is slightly different. IFA is not capable of providing this frequency response but it does have commercial arrangements in place between the French and the UK system operators that allow effectively the interconnector to participate and offer balancing services, in the same way that generators may do once the market has closed. So IFA can offer potentially quite valuable and cost-effective services, whereby the French system helps us to balance the UK system, not even just at times of difficulty but just generally through the course of general operation of the network.
It does also have in place the same kind of services that BritNed has to be able to operate during time of system emergency, so arrangements between National Grid and RTE to allow those kinds of services to be provided.
Lord Broers: Do you know what the margin is in France?
Dr Ramsay: The generation margin?
Lord Broers: What is their minimum? Are they are 4% like us or are they up at—
Dr Ramsay: I am afraid I do not know the exact detail. That is something we can get back to you on. I think their margin is healthier than ours, but I believe that across Europe everyone is thinking about these kinds of questions.
Lord Broers: That is key, is it not? If there is a large high that creates a large cold system, France is going to be using a lot and Germany is going to be using a lot and so are the Scandinavians. So these links may not work.
Dr Ramsay: The links will work. Interconnectors will provide for flows and I think what is important is that all countries that we are connecting to do have some kind of margin. Those interconnectors that are more valuable in terms of providing, say, reserves or reserve services, would be where we are connecting to generation systems that are more diverse than our own—very different to our own. So, say, an interconnector to Norway, which is a predominantly hydro system, would have more capacity value than a connection to Ireland because, as has been pointed out, the Northern Irish system may be in more trouble than ours and the Irish system is much more similar to the UK system.
Q105 Viscount Ridley: On most days, I have been told, the Dutch and French ones are running at pretty well full capacity into this country at the moment. If that is the case, how do they help when there is an emergency? In other words, is there any spare capacity to suddenly give us power on a day when we have a demand?
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Dr Ramsay: The point is that they are always helping for that reason. So they are always providing capacity and always coming into the UK. In terms of emergency situations, let us say the flow is going in a different direction because prices up to real time have dictated flow in a different direction. Because of the arrangements that we have in place, because of the market arrangements that are in place, the interconnector can be turned round to be able to provide flow in the right direction, to be able to support the system.
Viscount Ridley: Are we normally importing electricity from France most days, because their nuclear power is relatively cheap?
Dr Ramsay: Yes, that is right. The flows are normally going in the right direction.
Viscount Ridley: If we suddenly get a day when the wind drops, it is very cold and there are a lot of people watching television or something, how can we increase that capacity?
Dr Ramsay: They are not going to run any harder, but that does not undermine the contribution that interconnection makes to security of supply.
The Chairman: There is not a lot of spare capacity is what you are saying, but it is nevertheless making a valuable contribution at the moment.
Dr Ramsay: Exactly.
Q106 Lord Hennessy of Nympsfield: How do you expect the role of storage and interconnection to change in the future, particularly as electricity gets more and more decarbonised?
Anthony Price: I will pick this one up then. If you look at variable generation, typically from renewable energy sources, it has a number of implications on the network. At a centralised level, the system operator has to maintain frequency against a landscape of variable generation and, indeed, a more variable demand. When both the demand and the generation change, perhaps in opposite directions and at the same time, fast-acting response is necessary. Therefore, we expect to see a requirement for much more fast-acting response. Electricity storage is one of the four key tools to carry out that task. The four tools are: flexible generation, interconnection, variable generation and storage. You could argue that storage is perhaps one of the most certain of those because if you know it is there and it is going to work. So we expect storage to be used to maintain system frequency at the national level, as well as absorbing some of the so-called wrong-time energy that is produced, in order to play that back later, and often that could be at the regional level.
Ofgem have published figures giving details of the cost of rewiring Britain. Rewiring Britain is important because, as we move on to variable generation and renewables, and we start taking energy from fossil fuels into transport and heating and putting it on to the electricity sector, we could see the current peak load go up from 60 gigawatts—by using electric transport rising to 110 gigawatts, and if we have all-electric heating going up to 220 gigawatts. With those sorts of figures, the only way we can manage that is to put in storage locally in order to make sure that our local system does not get overloaded as well.
Lord Hennessy of Nympsfield: Can I ask Professor Strbac a supplementary? I have heard it suggested that storage is one of the great possibilities for transforming—I think that is the verb—the electricity scene. If we can get breakthroughs there, which are foreseeable, this will make a huge difference, and it is not speculative it is there for the taking. Is that your assessment?
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Professor Strbac: Do you want me to say?
Lord Hennessy of Nympsfield: I was asking you, yes.
Professor Strbac: We have carried out analysis of economic and environmental performance of the GB system from now to the future in 2050. Regarding storage, it is certainly one of the technologies that potentially can facilitate cost effectiveness in relation to that future. Just to give you an insight—you have already hinted, regarding the questions about the efficiency of storage—our analysis suggests that, if we are to build the system now, we will be on the verge of building Dinorwig because the business case for Dinorwig was marginal.
Lord Hennessy of Nympsfield: The north Wales type of thing?
Professor Strbac: Yes. But on the positive engineering side I cannot resist not saying that if you ever go to North Wales—if you happen to be there—go to see it. It is a great engineering achievement. The electric mountain is phenomenal.
However, analysis suggests that the kind of elephant in the room with storage—with Dinorwig, for example—is that, although we cannot agree what the investment cost of that technology is, it is between three and five times more than a conventional gas generator. As we discussed, it wastes 25% of energy you put in. How desperate do you need to be to be building high investment cost plant that wastes 25% of the energy you put in? The systems going forward, with nuclear, wind and CCS, are becoming so difficult to operate that our analysis suggests we want to have seven Dinorwigs in 2030.
Of course it is indicated there are other technologies that can also support that system. Anthony has mentioned interconnection and flexible generation, but also demand-side response is certainly potentially a massive contributor to this. We have done the analysis regarding the competition of these sources in the provision of these fundamental services, and there is in fact, quite interestingly, quite a lot of synergy between them. So these technologies do not necessarily exclude each other completely from the game, although our analysis suggests that probably the strongest competition would be between storage and demand-side response. That depends how that future develops, what the cost is and so on. All of these technologies have a role to play, with significantly increased volumes, in running low carbon electricity system cost effectively.
Q107 Lord Broers: I have a simple question about storage and latency. At the moment, we have about 5% of our storage. Now, once the water is down the hill, how long does it take to pump it up again? If we use it all up in one day, how long does it take to pump that water back up? We are unlikely to be able to pump it up the next day if the high is still sitting over us and it is still cold. I think there must be a derating on the storage capacity we have, because of this problem—the same as with batteries. Admittedly, a lithium fluoride battery charges much more quickly than previous ones but pumping water up a hill does not necessarily get quicker, does it?
Anthony Price: May I take that question please? If I can give a bit of an introduction to try to simplify matters, the first point is that the parameters for storage often confuse people. We know that there is generally a misunderstanding between energy and power and energy and electricity. You need to think of storage, both in terms of its power capacity—so let us say its rated power—and also have an idea of how much energy can be despatched or the duration of time for which that power can be despatched. So a typical lithium battery or even, say, a car battery, if you discharged it at its nominal rate would take about an hour to discharge.
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Dinorwig takes five hours to discharge. If there is an inefficiency loss, a simple rule of thumb can be: it takes the same time to charge as it did to discharge, but you need to charge at a higher rate to overcome the inefficiency.
Could I just make a point about inefficiency? I know everyone here has very strong scientific backgrounds and is very good in maths. But to simplify matters, when you think of electricity storage—forget your physics lessons—the best way of describing it is that you take in energy that is often low cost and you give out power, which is of high value. If you put that in mind, although Goran is saying that it appears that we are wasting 25% energy, actually, at the time that you want the output from the storage device, whether it is Dinorwig or whether it is a battery, you really want the power and it is the power at peak times that is valuable. We know that just by looking at the prices in the power market.
Viscount Ridley: Can I just pursue this point about efficiency and wastage a little further? There is a term called “energy return on energy invested”. In other words, if you build a technology like wind, you use a certain amount of energy in building the turbine, maintaining it, backing it up and all that kind of thing. Hopefully, you get more energy out of it than you put in—that is the general idea. When you add the need to store that energy, even in pumped storage and therefore waste 25% of it, according to a German analysis I have seen you make it uneconomic in energy terms—not in financial terms but in energy terms. Your energy return on energy invested is getting too low to be worth doing. Do you accept that analysis?
Anthony Price: I have seen these analyses and I am never quite sure which side to believe. Your point is well made, and you can look at some types of battery where clearly the energy used to make the battery is far greater than the energy you will ever get out from it in its lifetime. Pumped hydro typically will have a lifetime of, say, 80 years if it is given a refurbishment at the mid-life point. So these questions are very important questions and I must confess I do not know the answer to them.
Lord Peston: I just got a bit loss on Professor Strbac’s answer to Lord Hennessy about storage. In a way, if you look at batteries, storage is one of the greatest inventions of modern life. Most of us could not run our lives without batteries. But what I was not clear about—this slightly anticipates where we are going in a later question—is: where would research into storage stand on your research priorities list? I was not very clear. At one point you seemed to be saying, “It is a waste of time” and another point you were saying it was of the essence, and I became a bit lost.
Professor Strbac: I wanted to demonstrate how the importance of storage going forward would increase very significantly—exponentially, if I can use that word. Regarding your question, if we do more research, obviously there are challenges because it would be great if the cost of storage could be reduced. In that context, what our analysis very clearly suggests is that the UK, given that we are an island, would need storage earlier than other countries—earlier than Europe, for example, because Europe is much more interconnected and there is a very significant diversity of demand and supply.
Now the question is—which we have posed and there was some positive response to this—can we turn that problem into an opportunity for the UK and start potentially leading research and innovation in the area of energy storage, and then solve the problem here and offer that technology elsewhere? As I say, I was quite pleased that there was a significant investment, which we think was well justified, from the Government to research
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organisations to start working on the hard core of new technologies that would be potentially much more cost effective than what we currently have, in order to solve our problem but also to potentially try to lead the work at the international level. I do not do work on storage technology itself—but the UK has a very significant capacity in the research areas of storage technologies. I think this is quite important.
Anthony may not fully agree with this, but the present technologies of electricity storage that are being applied to the grid did not all have the grid in mind when they were designed. For the batteries in my mobile phone—the core criteria are low weight and low volume. If we build grid-scale storage, it is useful to have that, but lower cost will be the core criterion. There are new technologies emerging and, as I say, the UK is leading some of these developments at the international level. I think that is potentially a good use of resource to try to make breakthroughs in using technologies that are not yet in the market. Currently, if you talk to big companies, they do not have very large orders on their books, so there is not a huge amount of work on developing new technologies, and that is an area that I think will be useful to continue and develop, because if we get this right the benefits will be enormous.
Lord Winston: Just to continue on the storage issue, can we have an idea of what progress has been made in developing grid-scale storage, which obviously is a game-changing technology, and bringing the cost down? We are hearing quite conflicting evidence about that and it would be helpful to hear your views.
Anthony Price: Thank you. If you talk about grid scale, to a certain extent that is a confusing statement. It could mean anything from power capacities of, say, hundreds of megawatts possibly down to the order of, say, 1 megawatt where it is still of value to the distribution network operator.
To take a brief snapshot, if you were to put in pumped hydro now, you would choose a good site and you would put the best available equipment in. In fact, CIGRE, the international committee for large-scale generation, did a study on various storage types a few years ago. Surprisingly, the costs of pumped hydro are about the same as they were when we built Dinorwig. So pumped hydro, if you have the site, is still the premium technology to go for.
Also it is interesting to look at the mechanical systems, such as compressed air, liquid air or cryogenics, because these typically have long lifetimes. If you can double the lifetime of a plant, you make a substantial impact on its cost benefit. I should not forget flywheels, which are very low cost in terms of the cost per kilowatt installed. Flywheels often get associated with short duration, but there is a considerable amount of work going on to develop longer-duration flywheels—flywheels that can discharge energy over an hour or more. These again have a benefit of long lifetimes.
When we come to the world of batteries, there is everything going on. The cost of lithium batteries has halved in the past three or four years and is likely to go down by another third in the next two to three years. We are looking at flow batteries, which is a very interesting area. There are new technologies emerging. The United States Department of Energy is supporting a number of programmes looking at the use of quinones to make organic flow batteries. Essentially this is using rhubarb-type chemicals to produce very low-cost battery systems.
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So in terms of promise, there is a great deal. But what I also want to say is that there is a lot of storage going in at above 1 megawatt size in the new technologies. I can think of three battery companies that are able to produce between 500 megawatts to 1 gigawatt of batteries per year, and they are looking to double or treble that in the coming four or five years. If we look at North America, we look at Germany, we look at Japan and Korea, and indeed China, batteries are moving like hotcakes.
Q108 Lord Winston: We gather there is around £18 million of government money going into research and development for new methods of storage. Is that an appropriate sum, do you think, because the Americans seem to be focusing much more than we are on these technologies and may want to sell them of course?
Anthony Price: In my opinion—if I may, Lord Winston, to get in before Goran does—yes, we are doing the right thing. We are investing a reasonable sum of money. It is not as much as the Americans are investing. But the area where we are falling short is that we have not put as much money into demonstration as the Americans have done. The multi-hundreds of millions that the Americans have put in has included sufficient money for the technologies to be demonstrated at grid scale. The American Government has supported battery installations of 20 or 40 megawatts. We have not done that. In fact, we have the rather perverse situation that one Government department is putting money into research and development—typically at our universities—but we struggle with another department to try to create a market framework where those technologies can be put out and demonstrated that they work.
Professor Strbac: If I could add to this, I agree at the high level, yes. But there are demonstration projects—and we are party to some of those—supported primarily by the low-carbon funding initiative from Ofgem, but also in various cities across the UK there are technologies where we do demonstrations.
There are two sides here. It is obviously good to understand how it works and how we make use of it, but again the technologies that are being demonstrated are still too expensive for the present situation. What I think we need potentially is to develop new technologies and test new ones that have not yet been developed. I am not an expert in storage technologies but I work with colleagues who are in that area. There are strong developments in new technologies and hopefully we will be able to test and work on those in future.
One element that I would like to mention here, which we have not touched upon, is that storage provides multiple value streams to the electricity system. Small-scale solutions could help with delaying or eliminating reinforcements of local distribution networks, they could support the transmission network and they could support balancing and security of supply. An area that requires a lot of work, and the UK is moving into—not necessarily at high speed—is to make sure that our arrangements are able to recognise the value that storage will bring, so that the UK plc objectives, when you want to use storage, coincide with the investors’ objectives. Currently, you would struggle as an investor to make a case for storage. Some cases potentially could make sense if we had the appropriate commercial market arrangements in place, which would enable investors to access parts of the benefits that they deliver to the entire system because, as we know, the system is run by different commercial organisations and the interaction between them could be massively improved.
The Chairman: A lot of people want to come in. Lord Broers is first.
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Q109 Lord Broers: This question is about hydro. I read everywhere that we have looked into and used all the hydro that we could generate. I do not understand that. Surely we could build more dams. There are plenty of hills still in Wales and Scotland, are there not? Are we near a limit? Is that a financial limit? What is the nature of that limit?
Anthony Price: Let me come back with a more general comment. If you are building a hydro power station, you are looking at an investment for 40 years, 80 years plus, and it is exactly the same as putting in any other storage projects. If you are going to build something, you want to know that you have an income stream, and unfortunately at the present time there is no sensible long-term income stream that you can take to a project financier or a banker and say, “Sign on to this”. You could, with regret, say that storage is practically the only one of the green technologies that receives no subsidy or support in the long term. That is a major drawback to making any investment. There is a company that is looking to develop a small-scale pumped hydro project in north Wales. I understand they have received planning permission. They have an interesting business model that may possibly overcome this barrier. But they have spent a significant sum of money trying to raise the financing in order to do this. All the projects that I have been involved in, in the United Kingdom, to try to develop a battery project—save one—have failed at the last because we have been unable to convince the backers that the business model that we had would endure for more than a year and, therefore, there was no certainty of income and the project failed.
The project that Goran and I are jointly working on at the moment is able to go ahead because it is being done under the auspices of the Low Carbon Network Fund. So it has taken a Low Carbon Network Fund in order to make a large-scale grid project happen. The only other large-scale projects that are taking place at the moment in GB are those under the DECC innovation competition. I think that is the answer: we do not have a market and commercial structure that allows us to make a sensible long-term investment decision.
Lord Rees of Ludlow: I do not ask about R&D in general. We cannot clearly be world leaders in all these technologies of batteries, supercapacitors and so on, but we do surely need to ensure that we have enough expertise to be informed judges and customers. We want to avoid going down the same route as we did in nuclear where, from being leaders, we do not have even enough people to have an informed watching brief. So are you confident that we do indeed have enough expertise, in universities or in large companies, to be able to make the right judgments and seize on initiatives when something is developed anywhere in the world?
Anthony Price: I have just returned from a conference in Warwick last week. It was very, very encouraging to see the significant resource that is now going in, in our young people, in energy storage. That is really very pleasing. It is very disheartening to have graduates telephone me asking for jobs, expecting to get positions working in energy storage, because there are few, as no one is actually building stuff and moving it out. So we are taking the right steps at the early TRL stages, but we are not necessarily doing enough later on. It is in the demonstration and deployment that we may fall short against our foreign competitors. There are dozens of companies queuing up to enter Britain and Europe with their storage products. So, we are not only losing access to our home market when it arrives, but we are also losing access to overseas markets because we are not able to demonstrate our technologies from a home base.
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More significantly, of course, by not having storage there on the system we are losing that key part of our infrastructure. Perhaps I can also add a little bit. We do have storage that we do not see. Many sites have uninterruptable power systems, which are often battery provided. These are large-scale installations, some of them very big. They are economic because the cost of not having that would be significant, and they are an essential part of typically corporate and, in many instances, Government infrastructure. If it can be seen to be there in order to maintain power, it should also be seen as part of the infrastructure. If we move the debate on from the national system to one of involving the smart grid, one of the dreams of the smart grid was to have local self-healing grids. We need to have the right tools—and storage would be one of them—in order to make sure that micro grids and the smart grid can work.
Viscount Ridley: In the 1980s storage meant stockpiling coal at power stations, and the great advantage of that is you do not lose any of its energy. There is not a 25% wastage. If you ignore the decarbonisation imperative, is that a flexible and effective way of storing electricity?
Anthony Price: Sadly, no, because the real issue is: can you deliver the energy at the time you want it? Having a coal heap is fine provided that you have between six hours and 12 hours to start up that coal plant. What we need to do is to differentiate between storage that we are going to use in applications, almost as an insurance policy in the short term, and storage that we are using to balance energy for perhaps a two-week lull. If you think about it, it is a bit like a transport system where we need a combination of taxis, so that I can walk out of here and get a taxi to my next meeting, and buses and trains where we are just storing up people until we have enough of them and moving them in one go because that is economic. So we want to have the flexibility. It is the ability to get power on demand, which is of value now, and if we have a more renewable grid and a spikier demand, I believe we are going to need a more flexible response when that occurs.
Viscount Ridley: Gas would not help in that respect—
Anthony Price: Well, gas is quick.
Viscount Ridley: But not quick enough.
Anthony Price: There is a battery going in in Leighton Buzzard in two weeks’ time and that will be able to deliver power within half a cycle.
Viscount Ridley: Gas cannot do that.
Anthony Price: Gas cannot do that. We are talking about 10 to 15 minutes. So this area of providing frequency needs to be done on a second by second basis. One of the interesting points from North America is that, where they have used batteries and flywheels to provide frequency services, the amount of reserve that they need to carry has dropped. So for PJM, because they are using fast-acting batteries, the reserve requirement for frequency has gone down from 1% of peak capacity to 0.75%.
Q110 Lord Wade of Chorlton: I apologise I had to go out and deal with some other matters. You appear to be talking about large-scale storage facilities that are fitting into the grid and so on. What research is going on into household storage, so that a householder can have a quick use of facilities if his power goes off for two or three hours? Is there much research and development of those types of products?
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Anthony Price: There are some very good demonstration projects under the Low Carbon Network Fund, and the DECC innovation project, looking at household storage. There are three rules of storage: one of them says that the closer you put storage to the end consumer the higher value it has. People are putting in quite a small battery in their houses and these will make a significant impact to their own energy profile. Our internal estimates suggest there are possible savings of 5% or 10% to a householder if they were to use storage sensibly.
Lord Wade of Chorlton: Those are now available?
Anthony Price: Pretty much available, yes.
Baroness Sharp of Guildford: Can I go over what you have been saying and see if I am correct in my interpretation of it? What you are saying is that in the current circumstances there is no market, in effect, to develop storage facilities and, because there is no market currently, while we have the research going on, the demonstration plants cannot get through this barrier of having to prove that they are going to be economic if installed. In the meantime what we are doing—and this takes up the statement that you made right at the very beginning—is we are using essentially gas as our main means for balancing the market at the moment. We have the pumped storage but this is not used to capacity because they are using the combined cycle gas plants, and I know you were saying it takes a quarter of an hour to bring that on to but essentially you have some margin here of balancing it. But I think it is very worrying that we have the knowledge and the potential to provide this but we are not able to bring it forward and to use it.
Anthony Price: I think in answer to that, just to clarify a few points, the frequency response market is about 1 gigawatt. We have 3 gigawatts of pumped storage. So it is not surprising that not all of it is used to provide frequency. So that should be added as a clarification to my earlier statement.
In terms of the market, what we are seeing is that gas plant that is already operating—so gas plant that is producing energy because it is turned on—is able to provide frequency by varying its output up and down. It is doing that at a low margin of cost at the point at which it takes over from pumped hydro and it is that difference. To say that there is no market is an incorrect statement. I would not like to say that. The point is that the market is not readily accessible by providers of storage because storage is not generation but many of the products are more closely aligned to conventional providers of generation-type services.
We are in discussion with National Grid as a way of trying to overcome this. There are similar discussions going on in Northern Ireland, where there are two projects to build both a 100 megawatt battery and a 300 megawatt compressed air plant. These projects are at a difficult stage because the regulator and the system operator in Northern Ireland I believe are still in a mode where they are considering conventional plant and not best use of a greener technology.
Professor Strbac: This may be going into the detail, but it is incorrect to say that gas plant cannot provide frequency regulation. How we do that is we part-load gas plant and then it can increase power very fast. So gas plant can provide frequency regulation. The only question is how that competes against storage. When you run a gas plant part-loaded, you lose efficiency and you get the frequency response at the expense of taking energy as well.
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Secondly, regarding storage, something like Dinorwig cannot necessarily provide very fast primary response, because it takes time for the water to get from the top of the hill. So, in fact, CCGTs are better than pumped storage in terms of time. Let us get the detail of that right.
Regarding the markets, our analysis suggests that, in the present system, business case for storage plant, particularly new technologies such as batteries is not a straightforward, because it is still very expensive. The present system does not need this as desperately as we are going to need it when we start building more nuclear and wind and it is hence critical that we do all of that research, we do demonstration and we get ready to make sure we do that in a cost-effective manner.
The Chairman: We must move on and back to interconnectors.
Q111 Baroness Manningham-Buller: That is exactly what I want to say. We want to go back to interconnectors. I would like to ask, probably Dr Ramsay—whom we have not heard from for a bit—about the plans for interconnectors between the UK and other countries. How far have these developed? Is the regulatory framework right? Give us a bit of background. I am sure we will have some further questions on it.
Dr Ramsay: Things have been developing quite significantly over the last 12 months. As was pointed out at the beginning of the session, we are relatively poorly interconnected at the moment in relation to other countries in Europe, but there are plans over the next 10 years to be seeing probably around a doubling of our interconnection capacity. There are a number of projects that are on the verge of their final investment decision, so moving from development into the delivery stage, and that has been brought forward by a step change in the regulatory framework for interconnection. I think if we had had this discussion maybe 12 or 18 months ago, I would be in not too dissimilar position to Anthony in talking about a lack of regulatory and commercial framework that was a barrier of further investment. But what we have seen, with the decision from Ofgem in the summer time to bring forward their innovative cap and floor regime for interconnection, is that there is now a clear pipeline of interconnector investment that is looking to come forward between now and 2020.
Baroness Manningham-Buller: Why did they change their policy?
Dr Ramsay: The last interconnector investment was made around about 2007, which was building the BritNed interconnector, the connection to the Netherlands. That was done under what is known as a merchant regime. So network interconnection is not treated like the rest of the UK onshore transmission network. It is a merchant activity, which means that investors can come and build whatever they want. You do not get a regulated return. The money that you make is based on the arbitrage opportunity between the two markets. So BritNed was the last investment that we saw and there were some problems with the way that European legislation was applied to the BritNed merchant investment. Although the investment went ahead, it was not seen as being a particularly attractive route to go in the future because of the legislative and regulatory risk that was attached to that investment.
From that point forward, Ofgem was quite keen to see how the regulatory arrangements could be improved to still maintain the market-led approach, so as not to be putting a huge amount of consumers’ money into a regulated return and to maintain the market-led approach but provide a regulatory wrapper to sit around the investment. From around 2010
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onwards, Ofgem has been investing quite a lot of energy and policy thinking into how to generate this new regulatory regime.
Baroness Manningham-Buller: Has that brought in much more private investment?
Dr Ramsay: Not yet, but it is on the verge of being realised. I am the project director for the Norwegian interconnector. That is around €2 billion of investment that will be split 50/50 between National Grid and Statnett, the Norwegian system operator and transmission owner. That is looking to go to a final investment decision in March of next year. The Belgian interconnector, also within National Grid’s portfolio, is around €600 million of investment, again split 50/50 with us and the Belgians. That will go to a final investment decision in February of next year. So the next six months are quite critical for interconnector investment to see whether or not the regulatory regime has truly unlocked the next generation of investment coming through.
Baroness Manningham-Buller: I think it probably has.
Dr Ramsay: I am pretty confident. This is my job for the next six months and everything is really well aligned, so for the Norwegian interconnector on the Norwegian side they were recently awarded their trade licence, effectively, by their ministry. So the Norwegians are incredibly keen. We have a huge amount of Government support here for the project too.
Baroness Manningham-Buller: Professor Strbac, you want to comment.
Professor Strbac: Just to support that. Our analysis on maximising UK plc’s welfare suggests that the UK will benefit significantly from interconnection. Our analysis suggests all the projects that are proposed, currently 4.6 gigawatts, are a good thing to do. I am a member of the Panel of Technical Experts for DECC that is scrutinising the implementation of electricity market reform and the capacity mechanism, and we expressed a concern that interconnection has not been included in this. Some of the value streams that interconnection may bring will not necessarily be delivered, but will hopefully overcome that. However, another concern we have is that we might in fact potentially buy too much generation, in which case we may not necessarily benefit from interconnection—the benefits may not be possible to realise because we will have already spent the money, which should not have been spent.
Just to give you a little bit of an indication of how important interconnection is for security of supply, we have done work for DG Energy that demonstrates that, if we move away from a member state-centric approach to security of supply to a more Europe-wide approach, we would need to build 100 gigawatts of peaking plant less. That is an area that is developing but that is something that we think should take a high priority, given that there is obviously lots of concern about security of supply. Interconnection can make a massive contribution here, and that is an area where we think we need to develop further arrangements.
The second element is what was mentioned about the short-term benefits, in terms of not only shipping nuclear power energy to the UK—a kind of energy arbitrage—but also to make sure that interconnection can be used for balancing demand and supply in real time. We do not think we are using that fully.
The third value component of interconnection, which I mentioned, is the contribution to security of supply, which has not been fully recognised within the market regime at the moment.
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Q112 Lord Broers: I will move on, Chairman, to the final question here. My question relates to that to a certain extent, and we have discussed this a lot already. Is enough known about how interconnectors will function and whether they will contribute to or disrupt system stability? My somewhat supplementary question is an engineering question: is the cost of interconnection linear with power or not? I would imagine that it is not. That is, if you built a connector that could deliver twice the power, it would not cost twice as much.
Dr Ramsay: That is right. The Norwegian interconnector is 1.4 gigawatts. If we built it at 1 gigawatt it would be roughly the same amount as it is now. It is a non-linear relationship, so, while the cable is very expensive, there is a certain fixed cost in building the two converter stations at either end and then you can have a slightly larger cable, slightly more capacity, without having a linear increment in cost there.
Lord Broers: So we might be being foolish there. Perhaps we should build it at 3 gigawatts?
Dr Ramsay: There are also other technology limitations that mean you can only go up in certain increments and then the step change in cost becomes again non-linear but, once you get to a certain scale, you cannot go beyond without seeing a much bigger increase in costs.
I know we spent quite a bit of time talking about some of the challenges around storage in terms of whether or not it can be cost effective with other balancing technologies. One of the benefits of interconnection is that with all of the different options that you have, through being able to balance the system, it is a very competitive technology to be used right now. So while we only have a limited amount of services, because we only have a limited amount of interconnection, we would see it as being a very cost-effective tool to support balancing of the system. It is not the only thing but it should be part of a portfolio of tools that the system operator can use, and we see that interconnection will play a big part in helping to balance the system in an intermittent and variable feature that you would see coming with high penetration of renewables.
The Chairman: Yes, quickly because we are coming to an end now.
Professor Strbac: Just to expand a little bit on the limitations regarding regulatory and commerciality in this context, what our analysis suggests, for example, is that this interconnection from Norway would bring massive benefit if it was going via Dogger Bank, where there is the largest offshore wind resource in the UK. Given the big offshore resource we have—and given the fact that you just said that there are massive economies of scale costs when you put interconnection in—if you went via Dogger Bank, then in a few years’ time if the offshore wind happen to materialise, we may be saving more than £0.5 billion. The option value of that in our view would be great, and we think that the UK should start looking into this.
The interconnection could provide additional value streams such as potentially connecting offshore wind farms on the way. But we have the problem that the offshore connection developments and interconnection are different businesses and they are not coordinated. I know that if National Grid was responding to commercial arrangements, which you would expect them to do, and if there was a more sensible approach to this, this interconnection would go via Dogger Bank.
The Chairman: A last question from Lord Dixon-Smith.
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Q113 Lord Dixon-Smith: Chairman, I understand interconnection is a very easy thing to do if you are part of mainland Europe—you just run the cables up to the border and go straight over—whereas, of course, doing interconnection for the UK, because we have a large maritime barrier wherever we do it, even if we cross the Dover Straits, is a much more expensive solution. Surely, in the final analysis, whether that is worthwhile or not comes down not to the actual technology but the actual cost in relation to paying the insurance premium to cater for variable situations within our particular islands. I wonder if you have any information you could give us that would indicate which way that equation is likely to work out.
Professor Strbac: Our analysis very clearly suggests that the UK would benefit from having more interconnection, particularly if we go forward with low-carbon generation such as nuclear and wind—being connected, for example, to Norway and have the balancing of demand and supply. It is expensive, I agree with you, but the value of it is bigger than the cost. All our analysis very clearly demonstrates that the UK will benefit from increasing interconnection very significantly.
Lord Dixon-Smith: I see that, but you have not yet quite told me that that is going to cost less than providing the cover for a big variation in this country. That is the question I am asking.
Professor Strbac: Not yet. There are four core technologies that can help us in terms of balancing our own demand and supply: storage, interconnection, more flexible generation and demand side. What our analysis suggests is that, when you put these choices into our models and you put in the costs for these choices—and I can tell you that it wants all of them to some extent—certainly interconnection is very beneficial for the UK, including all other options.
The Chairman: Between you, I think you have given us a clear steer that interconnection is going to be a part of the portfolio and probably cost effective. I am sorry we have run out of time. In fairness to those who are following we must close this session. We have learnt a lot about storage, interconnection and the like, and thank you very much for your help. I think, Dr Ramsay, you did say you would be able to give us some further information, at one point. If you would like to follow that up, please do so—and, indeed, if the others have any further information that they wish to send, we would be very happy to receive that. Thank you again for your help.
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Energy Networks Association (ENA) – Written evidence (REI0041) Introduction Energy Networks Association (ENA) represents the “wires and pipes” transmission and distribution network operators for gas and electricity in the UK and Ireland. Our members control and maintain the critical national infrastructure that delivers these vital services into customers’ homes and businesses. ENA is responding to this inquiry on behalf of its electricity members and in support of their own individual submissions and the submission of the E3C’s Electricity Task Group. Since privatisation in 1990 the UK’s energy networks have a strong track record of investing in safe and reliable energy infrastructure. The overall reliability of the transmission system was consistently high over the last price control period (2007-13) and well over 99.99% across all three electricity transmission networks in 2012-13. In the distribution network, the chance of a customer experiencing an interruption (that is, how often the lights go out) to their electricity supply reduced by 17% between 2002-03 to 2010-11. Over the same period, the time that the average customer is without power (in other words, how long the lights are out) has fallen by 25%. ENA and its member companies work closely with DECC, the Energy Emergencies Executive (E3C and its Task Groups), other government departments and Ofgem to ensure the continued resilience of electricity networks and maintain and improve the industry’s response to emergency situations to ensure that customers continue to receive an extremely high level of service. ENA and its member companies support national fora on resilience, interdependencies and climate impacts, including the Cabinet Office Infrastructure Security and Resilience Industry Forum and the Defra sponsored Infrastructure Operators Adaptation Forum. Distribution Network Operators also attend Local Resilience Forums (LRFs) and ENA attends the LRF chairs meetings. Risk documents covering the main electricity network risks are issued to LRFs and companies are in regular communication with them. This engagement helps to ensure good communications with the civil resilience community The main threats/challenges for the country’s electricity networks are considered to be due to severe weather, including flooding and the impact of climate change in the medium/long term. A recent report published by The Committee on Climate Change praised UK electricity distribution and transmission companies for implementing comprehensive strategies to safeguard the resilience of their networks to climate change. Weather impacts are generally more prevalent on Distribution Networks which are more prone to wind-blown material, falling trees and other weather impacts.
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Network Design UK electricity networks are designed, constructed and operated to very high standards and this results in supply reliability for customers which are comparable to the best in the world. These design standards provide increasing levels of resilience as the demand on a particular part of the network increases. This principle helps to ensure that where the network supplies a greater number of customers increased redundancy is built to provide a more robust network. These levels are set out in industry codes supported by regulation. Network owners face a dual challenge from potential climate change impacts:
Networks must be protected against the direct impacts of a changing climate e.g higher temperatures reducing the capacity of overhead lines and underground cables and
Networks must be able to cope with the changes in loading as a result of low carbon targets driving increased solar and wind generation and increased load from heat pumps and electric vehicles. Smart techniques are being developed and employed to reduce the cost of connecting these devices whilst retaining the reliability and resilience of the network. Companies have responded to this challenge, particularly through the Ofgem Low Carbon Networks Fund (now Low Carbon Networks & Innovation.)
Finally, Network Operators must be ready to respond to the challenge of a technical failure or part failure of the grid system or shortage of generation leading to either a “Black Start” or the need for Rota Load Disconnection under The Electricity Supply Emergency Code.
1. Flooding Resilience
The serious incidents of flooding in the South Midlands and South Yorkshire during the summer of 2007 highlighted the potential vulnerability of electricity substations to major flood incidents from current levels of flooding. Following the 2007 floods an ENA Task Group was set up to produce a common approach to the assessment of flood risk and develop target mitigation levels that could be subject to cost benefit assessments. This was enabled by the great improvement in information on flood risk in recent years. The Task Group comprised representatives from Networks Companies, DECC, Ofgem, Environment Agency, Scottish Environment Protection Agency, Met Office and the Pitt Review Team. This group developed an industry Engineering Technical Report (ETR) 138, Resilience to Flooding of Grid and Primary Substations. The report was accepted by E3C and companies are now undertaking a programme of work to improve substation resilience to flooding. This programme was agreed by Ofgem when they set the current allowances for Transmission and Distribution companies as part of the
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regulatory control periods. The respective allowances are published and expenditure monitored on an annual basis. This approach is held up as an exemplar by the Defra led Infrastructure Operators Adaptation Forum and details are published on the Institute of Engineering Technology web site. ETR 138 is based on current flood risk and also provides an allowance for climate change based on latest evidence. When the ETR was developed there was insufficiently accurate information available on surface water flooding to justify expenditure on a protection programme. However, information has recently improved and the Task Group was reconvened to assess this in conjunction with EA, SEPA, DECC and Ofgem. As a result of this review, ETR 138 will shortly be re-issued with guidance on protecting sites from surface water flooding. Again, this will include an allowance for climate change impacts. All flood protection is due to be complete by 2023 with higher risk sites being completed early in the programme. In the latest floods, no major electricity substations were adversely affected and a number of sites were protected from imminent flooding.
2. Adaptation to Climate Change including research work with the Met Office and new work on likely changes to wind speeds.
ENA and members have sponsored ground breaking research on climate change impacts and have developed a report in response to the requirements of the Climate Change Act. The report covers:
Identification of climate change impacts on the functions of licensed electricity distribution and transmission companies
Proposed mechanisms for monitoring and actions to respond to the likely impacts of climate change.
A task group was assembled including DECC, Ofgem, Defra, Environment Agency, Met Office and other organisations. Electricity Network Companies across the UK have experience in operating in a range of weather conditions and have always used the latest information when considering current threats and potential climate change impacts. Most recently companies have worked with the Met Office on ‘EP2’, a report on up to date information and predictions about the impact of climate change.
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This latest report which took the threats from climate change projections and assessed the impacts on energy networks companies was a groundbreaking initiative that brought climate science closer to business applications. This was the first project sponsored by an entire sector to review the specific impacts of climate change on their industry. Supported by climate scientists, experts from the industry worked together to understand their precise requirements and developed practical applications and business strategies for a changing world. Further work has since been commissioned with the Met Office to build a risk model that quantifies the relationship between climate and network faults, and also the vulnerability and exposure of the network to these faults. The main impacts on electricity networks from the current climate change projections are:
Temperature—predicted increase.
Precipitation—predicted increase in winter rainfall and summer droughts.
Sea level rise—predicted increase.
Storm surge—predicted increase. At present there is no firm climate change evidence to support increased intensity of wind or ice storms, both of which can cause extensive damage to overhead electricity networks. The report considers each component of Transmission and Distribution Systems and uses current industry techniques to calculate the effects of climate change to 2099. The greatest risk is from flooding from rivers, the sea and surface water and this risk is being brought under control by the flooding resilience work discussed above. The ENA Climate Change Task Group has now been reconvened to consider the industry’s approach to the next round of reporting. One of the new initiatives is to re-examine the evidence for climate impacts on wind strength. National Grid has been supporting the RESNET project with Newcastle University and DNOs have joined this work. One of the project work packages is intended to provide a geographical weather generator for temperature and rainfall and a new wind model consistent with the latest climate change projections (UKCP09). DNOs are particularly interested in the work on the wind model and Newcastle University is currently working on this. The Committee on Climate Change, Adaptation Sub-Committee (ASC) recently produced a Progress Report—“Managing climate risks to well-being and the economy”. This report assesses the current state of resilience to weather and climate of infrastructure, businesses, health care system and emergency services. The ASC praised the preparations of the networks industry for its activity in climate change adaptation and its preparedness to address key challenges.
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The ASC reported that they found evidence that the electricity transmission and distribution sector are assessing climate risks, taking action in response, and reporting on progress against plans. They reported less evidence available within most other sectors. The ASC noted that the electricity transmission and distribution sector has developed technical standards for managing current and future risks from flooding and storms. These provide a consistent approach across the industry to identifying the most critical assets at the highest level of risk in order to prioritise action. Application of these standards is used to make a business case to the regulator for funding resilience measures that provide value for money to the consumer through the price control process. The process includes an assessment of the risks from climate change.
3. Overhead Line Resilience and Vegetation Management Electricity Network Operators have a legal duty to undertake tree cutting, now called "vegetation management", in proximity of overhead power lines for reasons of safety, for example in order to safeguard children climbing trees. This has been a feature of both past and current legislation. These safety clearances also provide clearance between trees and the adjacent overhead lines and thus inherently provide a level of resilience against tree induced faults during adverse weather conditions. That degree of resilience depends upon a range of factors including wind speed, the type of tree and the health of the tree. Following studies into a number of extreme weather events in the 1990s and early 2000s, Government consulted on new requirements for improving overhead line resilience under abnormal weather conditions. This led to an amendment to the Electricity Safety, Quality and Continuity Regulations (ESQCRs) which required Network Operators to undertake a risk assessed programme of "resilience vegetation management", coming into force from 2009. The Guidance to the Statutory Instrument pointed to the use of the ENA document, ETR132 ‘Improving Network Performance under Abnormal Weather Conditions by Use of a Risk-Based Approach to Vegetation Management Near Electric Overhead Lines’ (March 2006). Accordingly, Network Operators have to meet costs of vegetation management for both safety clearances and resilience clearances. These costs are considered by Ofgem as part of Price Control Reviews. As with flooding, the respective allowances are published and expenditure monitored on an annual basis.
4. Mutual Aid Agreement (NEWSAC) This is a well established voluntary arrangement involving the Electricity Network Operators of the United Kingdom and Ireland, and is designed to provide mutual aid and assistance to member companies in the event of severe network damage, normally as a result of the weather. The agreement allows field staff and equipment to be deployed quickly to the areas of greatest damage in order that customers’ supplies can be restored as quickly as possible.
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ENA provides the secretariat for the agreement and ensures that meetings of the members take place at least twice a year. One meeting is held in the autumn to prepare for the winter ahead and a further meeting is held in the spring to review any events over the winter. Other ad hoc meetings may be called at the request of members or ENA. In deploying staff across the country where they are likely to be working in unfamiliar surroundings and potentially dangerous conditions there are a number of safety risks and the agreement sets out procedures to ensure safe working practices. A key issue for DNOs is their preparedness to respond to the risks posed to their electricity networks by adverse weather. NEWSAC provides a forum for companies to share information on their planning for forecast events and then to share information. NEWSAC was successfully invoked during a number of the storms last winter, however, due to the widespread nature of the Christmas storm and the threatening forecasts across the whole country, the opportunity for staff transfers at that time was more limited.
5. Review following the Christmas 13 Storms ENA and the E3C Electricity Task Group ETG led on a number of initiatives including a review and update to the NEWSAC agreement. Also as a result of the DECC review, Good Practice Guides have been produced in conjunction with the Electricity Task Group for the following emergency management activities:-
Weather forecasting and escalation.
Providing estimated restoration time information to customers.
Provision of Welfare facilities. In addition, a review of documents relating to performance during severe weather will be undertaken during 2014/15 to take account of any learning points from the storms.Also, a considerable amount of work has been carried out to improve communication of key information to the public. One aspect identified during the recent storms was the need to make it much easier for customers to contact their local network operator in the event of a power cut and this has resulted in the substantial project to introduce a Single Emergency Number. Work is progressing to deliver this and the current timeline is for a completion date of April 2016
6. Sharing emergency planning and response techniques.
To support the work of E3C and the Electricity Task Group, ENA and its members companies operate a regular Emergency Planning Managers’ Forum to share best practice in emergency planning and response. This group also oversees transferring ETG initiatives into detailed actions, particularly if it necessary to establish a Task Group of member companies to develop an enduring ENA engineering document.
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This Group also carries out the detailed work on the public information systems that would be available in the event of a major power emergency including Rota Load Disconnection (RLD).
7. Cyber Security Increasing use of communications technology and data in the development of a smart grid will be vital to managing shifting patterns of supply and demand in the future energy system. However, it will create new vulnerabilities, with thousands of potential access points providing opportunities for cyber criminals. Through ENA the industry is working together and with Government to increase understanding and awareness around cyber security. ENA Energy Network Cyber Security Forum (ENCSF) has been established in order to:
Provide strategic direction on the emerging issues for energy networks arising from the risks to Energy Networks from Cyber threats ;
Ensure engagement with key stakeholders; particularly DECC, Ofgem and other energy industry organisations, so that DNO cyber security current and future issues are appropriately understood.
To actively assist ENA Member Companies in managing the administrative, engineering and technical aspects of cyber security issues arising from both existing infrastructure and the development and deployment of extensive ICT infrastructure (Smart Grids).
The Forum provides an opportunity for debate and development of strategic direction and will initiate work to assess the implications for ENA Members of cyber security threats or issues. Through this forum, ENA position is developed and communicated to DECC, Ofgem and other key policy makers in order both to influence the national debate and to highlight the strategic importance of the energy networks.
8. Low Carbon Technologies
Greater take-up of low carbon technologies like electric vehicles will see the increased electrification of our society and a doubling of the load on our electricity network. The Low Carbon Technologies Working Group has been established to represent network operators interest in several areas. The LCT assists with the development of UK Standards for Electric Vehicles (EV); Charging connections, charging infrastructure. This includes the development of the IET Code of Practice for the installation of charging infrastructure. At the European level the group maintains representation on Eurelectric’s task force for Electric Vehicles and keeps a watching brief on the potential of Vehicle to Grid (V2G) energy storage. The LCT maintains links with BEAMA, OLEV, Ofgem and MCS, to assist these organisations with developing appropriate strategy and procedures for the installation of various LCTs.
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These include the recent OLEV grant for domestic EV charging point installation, notification process for small scale embedded generation (SSEG) and also the Renewable Heat Incentive (RHI). 26 September 2014
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Energy Networks Association (ENA) and the National Grid – Oral evidence (QQ 53-68) Transcript to be found under the National Grid
Energy Technologies Institute (ETI) – Written evidence (REI0018)
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Energy Technologies Institute (ETI) – Written evidence (REI0018) Key Points 1. By 2030 the UK energy system should be sufficiently different from todays that lessons
learnt from current operations will have limited value in understanding future requirements. Unless these lessons are combined with sufficient evidence from large scale implementations (early roll-out) and subject to thorough evidence-based analysis, the risk of wasted expenditure and strategic failure is high. Although change is uncomfortable, the risk to the UK economy of discovering in the 2020s that we are on a track to an unaffordable, insecure and unsustainable energy system should compel us to move forward despite the challenges.
2. The next six years is a critical period for laying the knowledge foundations for progress to 2030 and beyond, given the timescale for planning and delivering major infrastructure investments.
3. This current inquiry has rightly focused on electricity. However, by 2030 we will need to
have made good progress in developing combined infrastructure strategies across the UK. In any area the balance between gas, district heating, electricity, building works and control in delivering a viable path forward for the major load of space and water heating will determine a combined investment plan across each of these three energy infrastructures. These plans will differ significantly from area to area.
4. These strategies combined with policies to incentivise investments by individual building
owners will shape demand profiles, in the light of consumer experience of the operation of energy markets to that point.
5. The generation mix will be shaped by government policies and incentives in combination
with the operation of markets. Market operation will partly be determined by government determined rules and partly by demand profiles.
6. The ETI continues to explore the design and operation of affordable, secure and
sustainable UK energy systems on a whole systems basis, including the transition steps from 2020 to 2030, on viable trajectories out to more or less attractive systems in 2050. A significant proportion of the technologies required for the 2050 system are already ready for first of a kind demonstration but require integration into effective systems, including appropriate policy, regulatory and market capacity, supply chain development and attractive consumer propositions. Although the major challenges are around this system development and the evidence base to underpin strategy development and build market confidence, some further component technology developments are required, such as improved detailed engineering of offshore wind systems, the applied science of hydrogen vehicles or the development of new systems eg domestic energy management systems.
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7. Our evidence identifies a number of options for increased system flexibility at affordable cost from 2025 onwards. It is likely that a robust system will adopt a suitable combination of these options. Many of them require market and physical infrastructure development to support them. ETI work on the most appropriate combination of these options is ongoing. Very detailed whole systems operation analysis and technology characteristics analysis are required. However, distributed heat storage, dramatic improvements in the cost and performance of distribution scale electricity storage, hybrid fuel/electricity systems and the use of CCS in both pre and post combustion modes in combination with geological storage of natural gas and hydrogen all appear to be viable contenders, with some carrying lower risk than others.
8. Although it seems likely that there will be advantages to more interconnection, there is
no basis for forecasting the supply and demand balances across neighbouring European countries. Interconnection creates deeper markets for supply and demand at significant cost and the impact on energy security can be positive or negative, depending on choices by others.
9. Our modelling highlights new nuclear as a key component of a future low carbon energy
system, providing a core low carbon power generation capability and increasing security of supply by increasing diversity of supply and establishing a base-load generation capability alongside fossil fuel plants with CCS. Without investment in a major new nuclear build programme, the cost and difficulty of meeting the UK climate change targets will rise very significantly. We consider that Small Modular Reactors (SMRs) may have a potential role in the UK future energy system in concurrent deployment alongside large base-load Generation III+ designs. SMRs would offer the additional potential to energise major heat networks through waste heat recovery, and provide electrical network balancing through provision of more agile and flexible electricity output than large nuclear plant.
10. The ETI continues to build the real world evidence base and analytical tools and
capability to underpin targets for technology development, systems design and market confidence. Our Smart Systems and Heat Programme is developing tools for area energy strategy support, evidence on consumer drivers and segmentation, real-world experience of cost-effective buildings retrofit and component technologies such as intensive heat storage and Home Energy Management Systems. Integrating this with the detailed outputs from our other technology programmes and market, policy and regulatory analysis is building a whole systems evidence base and capability.
11. Our technology investments also support product development by UK companies,
provide the evidence base that DECC, Devolved Administrations and Local Authorities require for their strategy development and support the design of sufficient scale demonstrations to provide the evidence base required for real market confidence for supply side and demand side investments.
Short Term to 2020
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12. The ETI is not best placed to comment on specific short-term measures to manage supply and demand out to 2020 as this will be based on ongoing assets, asset retirements and some new assets already well within the project pipeline. We have therefore limited our response to the following issues.
13. The evolution of supply and demand to 2020 is hard to predict as it is driven by factors such as Government policy changes (eg the sudden implementation of a PV FIT), consumer technology changes (such as the uptake of LED lighting), investment decisions (for example replacing electric resistive heating with gas boilers or electric heat pumps) and the general affordability of electricity in relation to disposable incomes and global competition of energy intensive industries.
14. We see no reason why current structures, if skilfully implemented, will not ensure
sufficient system capacity and flexibility out to 2020. However, there could be significant excess or insufficient capacity provision given the challenges in accurately forecasting the balance.
15. The most likely significant differences from the situation in 2014 are more areas of
distribution systems stress from local concentrations of PV installation and oversupply of electricity when demand is low, a higher proportion of wind generation and less reliable operation of the remaining nuclear fleet. All of these will create more and unpredictable demands for system services to be provided as a bolt-on to the system rather than as part of the design of the mix.
16. Domestic Smart Meters will have some impact on demand and peak smoothing, which
will depend on tariff structures.
17. Industrial and commercial demand management (or more likely supply of system services) has greater potential. An understanding of the energy using system and its business integration and implementation of business responsive controls is key to this area of demand management. Retail refrigeration and small scale industrial processes are areas of further opportunity, beyond individual large energy intensive processes (such as chlorine production).
18. Since both underused and mothballed capacity and demand management opportunities
are finite resources, the pricing of the services is likely to be set by competition with temporary generation and commercial strategies rather than derived from inherent costs.
19. During the period to 2020 it is critical to gather the evidence to support the decisions
taken beyond 2020.
20. Evidence from existing operations is currently tightly held within commercial activities, the System Operator and regulators. This should be provided to DECC and systematically analysed by a key team of technical and market experts to provide a coherent strategic evidence base.
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21. Taxpayers and consumers support large scale demonstrations and trials through a variety of mechanisms at significant total cost. It is not clear that DECC has been given the levers to ensure that the design of these trials will provide the evidence they require and that they have sufficient access to the outcomes.
22. Given the pace of change in electricity markets between now and 2020, the scale of
investments in demonstrators and evidence collection and the increasing interaction between electricity and other energy vectors beyond 2020, it is critical to ensure that this evidence collection and analysis is coherent and sufficiently resourced. The additional costs to energy users and taxpayers of decisions taken on weak evidence would be of a scale out of all proportion to the costs of providing robust evidence.
Medium term to 2030 23. We anticipate that the demand side will have shown limited change, apart from the
impact of efficiency measures, more sophisticated energy management systems and response to changing market structures by 2030. Although various policy mechanisms are likely to create large scale experiments in new demand technologies, they will need to be scaled up as electricity supply is decarbonised, especially as our modelling shows there are lower cost options than electric vehicles and heat pumps to deliver carbon budgets to 2030.
24. Nevertheless, a demonstration fleet of up to a million hybrid electric vehicles or heat-pumps (around 3% of the population of vehicles or buildings) would have a measurable effect on national demand profiles. Natural clustering will almost certainly lead to dramatic loads on some local distribution systems, even at this level of national penetration.
25. Current industry thinking is to identify areas where clustering will occur and reinforce
these selectively. It is not clear that we have the planning and delivery capacity to do this effectively and especially speedily. There is therefore a risk of widespread reinforcements on a precautionary basis, combined with local overloads which take significant time to resolve.
26. Vehicle charging is a manageable problem, since the overnight load can be fitted into
the available system capacity. However simplistic charging management solutions will create unfortunate effects, such as cliffs of coordinated switch-on and switch-off. There are other issues that need to be addressed in designing an effective charging system. Unmanaged systems will contribute significantly to peak load, since people naturally plug in at the point of arrival home and then charge through the evening peak.
27. It is therefore critical that carefully designed vehicle charging management systems and
standards at the national level are developed and incorporated into any large scale demonstrations and early roll-outs. These systems need to address both the capacity of the national system and also the local distribution system.
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28. Although vehicle charging is potentially manageable, the local distribution loads need to be considered as part of the local area strategy for heat and the role of the electricity distribution system in any location.
29. Electric heating is not an inherently manageable problem, since it is inevitable that
everyone in an area will require heat on cold days and there is a real risk of distribution systems overload. Air source heat pumps have their lowest performance when it is cold and it is not economic to size them to cope with infrequent peak loads and they therefore usually include additional power through resistive heating, further reducing performance at peak demand. Depending on the detail of the local built environment, pumping heat out of the air around buildings and reducing building heat loss rates could further reduce heat pump efficiency.
30. The domestic RHI has been designed to manage these risks through controlling the pace
of adoption by level of support and requiring certain energy efficiency measures to be undertaken. Not only do efficiency measures reduce the total energy requirement, more importantly they enable the thermal mass of the building to be used more effectively to spread the heat load out over a day and reduce peak demand.
31. In order for peak management to occur: the electricity tariff must reflect time of day
costs of distribution sufficiently to incentivise the consumer; the building must have a relatively high thermal mass within the insulation and the control system must be capable of managing the heat source during the day against the thermal mass and comfort requirements in different parts of the building and hot water requirements, taking advantage of the tariff.
32. The ETI considers a hybrid system, which combines a gas boiler with heat pump as an
important transition technology to 2050. Burning gas in buildings will need to be almost completely eliminated if we are to meet our climate change targets. Although gas boilers might play a role in meeting infrequent cold weather peaks, it seems problematic to take up valuable living space with a rarely used system and to maintain a gas distribution system for rare events. However, hybrid systems could contribute to climate change targets while reducing peak loads on the electricity system and providing homeowners with superior economics at least out to 2035 and many could still potentially be in service in 2050.
33. Heat storage devices could also play an important role in managing peak heat load but
hot water tanks are now present in only 58% of houses in the UK, having been replaced by high power combi-boilers. Not only do these provide instant hot water which is always available, they free up valuable living space, which can also increase property values in some areas.
34. We consider two “typical house” examples below:
o Conversion from a combi-gas boiler (without heat storage) to an Air Source Heat Pump (ASHP) ASHP power is low compared to a gas boiler, so long pre-heating is required. In
low efficiency buildings, which leads to high losses while pre-heating and very
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poor responsiveness for householders. Fabric efficiency needs to be lifted to a reasonable standard, but this is likely to be expensive in older solid walled homes. High capacity heat storage is a route to improving responsiveness, but the technologies are currently immature.
Given the above, this example is for a relatively modern home with cavity wall insulation, loft insulation, double glazing, etc sufficient to avoid excessive losses during long pre-heating of the house. Heat storage in this example is only for water heating, where a heat output of at least 25kW is required and the 14kW heat output of the ASHP is nowhere near sufficient. Space heating will be significantly less responsive than the old combi-gas boiler.
The least cost (by far) route to heat storage from an ASHP is a hot water tank. Typically, this occupies a volume of 250-350 litres; space that will need to be found within the home. This will be sufficient for a typical family, but when the tank is empty it will take an hour or so to refill (assuming no space heating is also consuming output from the ASHP).
High temperature ASHPs are available to interface directly to the existing wet radiator system in the home with minimal changes. A typical unit is comprised of two boxes; an outside heat exchanger and an inside compressor unit both around half a cubic metre in size (an alternative configuration is a single external unit including both parts). The combination and including the storage tank costs around £7,000 plus installation. Significantly more space will be needed for the combination and storage than the combi-gas boiler occupied.
Across an area of typical housing we would expect the average costs of efficiency measures for all dwellings to reach the level of a post 1970s new build to be in the range £5,000-10,000 per dwelling, possibly more in some areas. This assumes significant development of new tools and systems approaches by the supply chain.
The diversified load across the houses in periods of cold weather is likely to be in the range 6-8kW, requiring major upgrades to the electricity distribution system, which would cost a few thousand pounds per dwelling (depending very much on the characteristics of the area) but only if executed as a part of a coordinated area strategy rather than a series of incremental upgrades. The cost of delivering sufficient building efficiency improvements to avoid these upgrades would be factorially higher and much harder to organise.
o Conversion from a combi-gas boiler (without heat storage) to a hybrid boiler/ASHP The gas boiler in hybrid combination yields similar responsiveness for both
space heating and hot water. A hot water tank is therefore not essential and sufficient fabric efficiency is not a prerequisite. However, a very significant proportion of energy consumption is associated with the rapid heating of spaces and hot water use. The proportion of heat supplied by the ASHP is hence directly related to fabric efficiency and hot water tank availability.
Given the above, this example is for an older home with solid walls and no external or internal wall insulation. Heat storage is not incorporated in this example, to avoid the requirement for finding additional space in the home.
Hybrid gas boiler and ASHP systems are available as an integrated package comprised of two separate boxes; an outside heat exchanger and an inside gas
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boiler combined with compressor unit both around half a cubic metre in size (alternative configurations are available). The combination costs ~£2,500 plus installation. More space will be required, but not as much as above. This is reasonably cost competitive compared to a combi-gas boiler replacement.
The diversified load across houses in this example is lower, perhaps 4-6kW in periods of cold weather.
35. By spending £1,000-3,000 extra per dwelling, optimising the design of the gas boiler and heat pump, integrating a different style of heat storage to shift electricity top-up and installing advanced controls it might be possible in many areas to reduce peak electricity demand to the level where smart network investments could avoid major upgrades. This would marginally increase the proportion of energy supplied by gas.
36. We have concluded that hybrid systems with appropriate smart controls and intelligent market design can contribute to both economic decarbonisation and peak/trough electricity demand management.
37. Heating with Air Source Heat Pumps alone appears to be close to the point where major electricity distribution upgrades will be required, even with all of the mitigations described in para 31. If vehicle charging is required in the same dwellings as those containing heat-pumps, then not only will the local sub-system be very likely to be overloaded, but the individual connection to the building may need to be replaced. Typical shared distribution capacity in the UK is in the range 1 to 3 kW/building and a typical connection rating for an individual building is 19kW. In buildings designed for electric heating, such as blocks of flats, the shared capacity is typically 8kW/building. The exact ratings vary
38. The evidence of consumer willingness to modify their demands to suit the drivers of the
System Operator is limited. Requiring consumers to reduce their washing and drying activities during periods of several days of very cold weather is not an obviously attractive strategy. Although some consumers may be constrained to do this by costs, we anticipate from our original consumer study work that many consumers will be willing to pay the additional costs of sufficient capacity, especially as this is relatively affordable. Without harder data on likely demand elasticity in a future world, planning capacity and the shape of the mix (from base load to rare peakers) will be guesswork.
39. We are aware of a number of electricity distribution studies which assume much lower
electricity demands per building when ASHPs are installed. Some of these have published their efficiency assumptions, which typically assume mass retrofits to deliver very high building efficiencies. The likely costs for these are an order of magnitude greater than uprating the distribution system, which makes this strategy very unappealing. Other studies have not published the detail of their assumptions about building efficiency and thermal capacity, heat pump sizing relative to cold day requirements, whether the heat pump economics have been optimised by including resistance heating and how the system is to be controlled within the building. Given the importance of these factors to the conclusions about electricity distribution strategies,
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we encourage the authors of such studies to publish these assumptions, not just a conveniently low assumed peak electricity demand.
40. District heating with combined heat and power in dense urban areas offers some of the
lowest potential costs of carbon saved in the period 2020 to 2030. In many areas district heating may well be the long-term solution, but with an increasing switch to lower carbon heat sources beyond 2030. The strategic flexibility of transitioning the energy supply without repeated interventions in millions of individually owned buildings has considerable attraction.
41. The design of energy centres for district heating in operation out to 2030 will depend
very much on government policy and market design. Economic efficiency for consumers would argue for a larger CHP element, smaller gas boilers and larger heat stores. The operation of these distributed generators could then contribute significantly to meeting peak electricity demands. By 2030 the national district heat network embedded generation capacity could range from less than 1GW to several GW, depending on government policy. It is possible that some of this could enter the capacity market, on the view that there will be a good demand for heat and that operators can choose between scheduling gas boilers, storage and gas-engines in response to customer demand and national market forecasts.
Background on the ETI 42. The Energy Technologies Institute (ETI) is a public-private partnership between global
energy and engineering firms and the UK Government. ETI carries out three primary activities:
43. modelling and strategic analysis of the UK energy system (power, heat, transport, infrastructure) to identify the key challenges and potential solutions to meeting the UK’s 2020 and 2050 energy and climate change targets at the lowest cost,
44. investing in major engineering and technology demonstration projects through targeted
procurement to address these challenges with the aim of de-risking solutions – both in technology and in supply-chain development – for subsequent commercial investors
45. providing support to enable the effective third party commercialisation of project
outcomes.
46. Recognising the need to focus and target investments to ensure value for money and leverage from public sector support, the ETI’s techno-economic modelling and strategic analysis of the UK energy system is a critical tool for supporting effective system planning and innovation delivery. The ETI approach is termed ‘ESME’ and is now used by DECC and the Committee on Climate Change to aid with policy development, planning and effective investment targeting.
47. Insights from ESME analysis have been reviewed with the European Commission and the
JRC. With their support ETI have now developed a prototype tool for use in assessing
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energy system design for the European Union area using the same approach used for the UK. A local (urban area) energy system planning tool ‘EnergyPath’ is in development as part of the ETI Smart Systems and Heat programme.
48. The UK energy system development and decarbonisation priorities identified by ETI are: Efficiency – introducing systems and technologies to reduce cost and improve buildings and transport efficiency. Nuclear – establishing a new build programme based on new supply chain capacity and increased investor confidence. Bioenergy – informing the science, technology and business cases for decisions on how to optimise the use of sustainable bioenergy resources as solid, liquid and gaseous fuels. Carbon Capture and Storage – providing system demonstration and strategic insights for capture, transport and storage building investor confidence. Gas – enabling long-term use of a critical fuel for power, heat, storage and potentially transport (‘gas’ = natural gas, synthetic combustion gases, biogas and hydrogen). Offshore renewables – reducing cost and building investor confidence. 19 September 2014
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Energy Technologies Institute (ETI), the Resilient Electricity Networks for Great Britain (RESNET) project and the Committee on Climate Change (CCC) – Oral evidence (QQ 124-138) Transcript to be found under the Committee on Climate Change (CCC)
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Energy UK – Written evidence (REI0034) Introduction Energy UK is the trade association for the energy industry. We represent over 80 members made up of generators and gas and electricity suppliers of all kinds and sizes as well as other businesses operating in the energy industry. Together our members generate more than 90 per cent of the UK’s total electricity output, supplying more than 26 million homes and investing in 2012 more than £11 billion in the British economy. Maintaining and improving the resilience of the electricity system is at the heart of what Energy UK’s members deliver for their customers via the investment they make in network and electricity generation infrastructure. We are therefore welcome the opportunity to submit a response to this inquiry looking at the current and future resilience of the UK’s electricity infrastructure. Executive Summary The electricity system is resilient in terms of balancing the system as there are a number
of tools at the disposal of the System Operator. This resilience will face a number of challenges up to 2030 so it is therefore important that Government, regulators, the System Operator and the energy industry work together to tackle them.
Capacity margins have been tightening in the last few years due to a number of fossil fuel power stations closing or mothballing. However, the right policy measures are being put in place via Electricity Market Reform, primarily the Capacity Market, to set the right investment framework needed to maintain long term security of electricity supply.
The level of electricity resilience in terms of capacity adequacy is set by the Secretary of
State via the Reliability Standard, which balances the security of supply requirements with cost to consumers.
Increased interconnection with the rest of Europe can improve resilience but as the flows
are determined by market prices, there is a prospect of exports at time of system stress if it coincides with a similar situation in interconnected markets. These risks and the powers of Governments to restrict interconnector flows need to be better understood.
There will be new challenges to resilience throughout 2020s as further thermal power
stations close. There will need to be sufficient baseload and peaking capacity is available to support and operate beside the intermittent generation on the system. This will be provided by a combination of flexible generation, demand side response measures and electricity storage. Government must ensure that the right policy and regulatory framework is in place to enable new technologies to compete in the market.
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Responses to questions Short term (to 2020) 1) How resilient is the UK’s electricity system to peaks in consumer demand and sudden
shocks? How well developed is the underpinning evidence base? Measuring resilience
1.1 There are a number of metrics which can be used for measuring resilience in terms of the ability to meet peaks in consumer demand and sudden System shocks. The most common of which are de-rated capacity margins and Loss of Load Expectation. De-rated capacity margin measures the amount of excess supply above peak demand. De-rating results in supply adjustments to reflect the proportion of electricity which is likely to be technically available to generate at times of peak demand. Loss of Load Expectation represents the number of hours per annum in which, over the long-term, it is statistically expected that supply will not meet demand. This is a probabilistic approach. The actual amount will vary depending on the circumstances in a particular year, for example how cold the winter is, whether or not an unusually large number of power plants fail to work on a given occasion, the power output from wind generation at peak demand and other factors which affect the balance of electricity supply and demand. However, it is important to note when interpreting this metric that a certain level of loss of load is not equivalent to the same amount of blackouts. In most cases loss of load would be managed without significant impact on domestic consumers.
Balancing the system
1.2 The resilience of the system is maintained by a set of market and system operation arrangements to ensure that demand is balanced with generation at all times, including:
Generators and suppliers use of bilateral trading or power exchanges to buy and sell power in the forward, day ahead and spot markets. All transactions are notified to the System Operator. After ‘gate closure’ generators and suppliers use the Balancing Market to ensure that individual positions are balanced.
National Grid in its role as System Operator has a number of Ancillary Services at its disposal which can be used to balance the system.
1.3 The System Operator is well prepared to handle sudden system shocks, for example sudden pickup in demand, or a power station failing to generate due to an unforeseen outage. Historical evidence shows that the system is very resilient to peaks in consumer demand.
2) What measures are being taken to improve the resilience of the UK’s electricity system
until 2020? Will this be sufficient to ‘keep the lights on’?
2.1 DECC, Ofgem and National Grid are undertaking a number of policy and regulatory measures to improve the resilience of the system up to 2020, particularly in light of
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tightening capacity margins over the forthcoming winters, as identified in Ofgem’s last two capacity assessment reports54.
2.2 The Capacity Market Historically the energy market has delivered sufficient investment in electricity capacity with respect to the required number of power stations needed to supply peak demand. However, in recent years there has been a rapid closure of coal fired power stations due to environmental regulations prescribed by the Large Combustion Plant Directive. This lost baseload capacity needs to be replaced however most of the new generation capacity that has been built in recent years has come from intermittent wind and solar farms. Capacity is required from conventional generation that can in future operate in a more flexible mode over shorter notice periods.
2.3 However, running irregularly makes the economics of conventional generation investment challenging. A greater proportion of fixed costs need to be recovered through scarcity rents at times of stress, which are unpredictable and difficult to base investment decisions on. Furthermore, energy-only market prices are not able to accurately reflect the value to consumers of having sufficient capacity to ‘keep the lights on’.
2.4 The Capacity Market, currently being implemented as part of the Government’s Electricity Market Reform programme, has been introduced to mitigate the risk that an energy-only market fails to deliver sufficient incentives for reliable and flexible capacity.
2.5 Under the Capacity Market, the Secretary of State will determine the reliability of the System required and total amount of capacity to be procured via an auction. Successful bidders, whether from generation, storage or demand side response, will be required to generate electricity or deliver reductions in demand during system stress events. If not, penalty payments will be applied.
2.6 The first Capacity Market auction is due to take place in December 2014 for provision of
capacity from winter 2018/19 onwards. Energy UK believes that the Capacity Market is the right intervention to set the framework for investment in capacity for both existing and new capacity when needed to replace expected plant closures.
2.7 Supplemental Balancing Reserve and Demand Side Balancing Reserve Following publication of its 2013 Capacity Assessment which showed tightening margins in the mid-2020s before the introduction of the Capacity Market, Ofgem and National Grid decided that it would be appropriate for additional balancing services to be procured.
2.8 The Supplemental Balancing Reserve is primarily aimed at retaining generation capacity on the system that is either currently mothballed, or has the potential to, due to poor
54 Ofgem Capacity Assessment 2013: https://www.ofgem.gov.uk/ofgem-publications/75232/electricity-capacity-assessment-report-2013.pdf Ofgem Capacity Assessment 2014: https://www.ofgem.gov.uk/ofgem-publications/88523/electricitycapacityassessment2014-fullreportfinalforpublication.pdf
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market conditions. The Demand Side Balancing Reserve is aimed at bringing forward demand side response provision to dampen the peak. It would also be a last resort option but called upon before Supplemental Balancing Reserve.
2.9 Energy UK recognises the need to ensure that there is sufficient capacity in the winters until capacity payments start. However, distortions to the energy market and dispatch in the balancing market must be minimised to avoid unintended consequences. Furthermore, a targeted strategic reserve would not be able to resolve the current challenging economic conditions faced by conventional generators, or incentivise investment in new capacity that is required in the longer term. For this reason the Capacity Market is the primary tool for longer term security of supply.
2.10 Cash-out reforms Imbalance pricing, also referred to as cashout, is a key part of the wholesale trading arrangements in Great Britain. The wholesale electricity market is set up such that bilateral contracts are entered into in order for generators to be able to sell the energy they produce onto Suppliers to supply their customers. For any given half hour Settlement Period, Parties may trade with each other up to a point one hour beforehand, known as Gate Closure. Parties are incentivised to balance their position for a given Settlement Period such that the amount of energy they generate or buy matches the amount of energy they consume or sell. However, there are circumstances where this does not happen, such as a generator experiencing an unexpected technical problem that does not allow it to generate the expected amount of energy, or a Supplier over or under estimating the amount of demand its customers actually use. This would result in a Party being in a position of imbalance. Trading will then take place within the Balancing Market in order to balance its position.
2.11 In 2012 Ofgem launched a Significant Code Review of the electricity balancing arrangements which it believes revealed that cashout prices calculated under the existing regime do not reflect the cost of actions taken by the System Operator to balance the system. Therefore Ofgem proposed a suite of reforms to make cashout prices more punitive to incentivise parties to improve balancing and reward providers of flexible capacity who can help balance the system. Following publication of its final policy decision in May, Ofgem instructed National Grid to raise two change proposals within the Balancing and Settlement Code modification process to implement the changes to the cashout regime. Implementation will be staggered over the period between winter 2014/15 and winter 2018/19.
2.12 Energy UK supports the principles behind changes to cashout, as efficient balancing is in the interests of consumers and the reliability of the system. However, implementation must be done in a proportionate way to allow parties time to adapt to the new regime given the significant impact on the risks of operating in the market.
2.13 Interconnection Interconnection between GB and other countries contributes to the resilience of our electricity system. There are currently four interconnectors providing connections to Ireland, France and the Netherlands with a combined import capacity of 4.3GW.
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Currently the Irish Interconnectors predominantly export from GB to Ireland due to the ability to attract higher Irish prices, whereas the French and Dutch interconnectors import to the UK leading to a net average transfer to the UK of 1.5GW during 2013. There are proposed plans for further interconnectors up to a potential capacity of 7GW, although most of these cannot be built until the 2020s.
2.14 Ofgem is undertaking a review of the regulatory regime for interconnectors and is
adopting a ‘cap and floor’ approach for the upcoming projects to improve the attractiveness for investment. In addition, from 2015 either interconnectors or overseas capacity will be able to participate in the Capacity Market auctions.
2.15 The flows of interconnectors are determined by the differential in prices between markets. This should levelise as the markets across Europe are coupled due to European integration, although the carbon price will also act as a differential. The expectation is that when margins tighten in one market the price will rise, thereby ensuring that electricity flows in the right direction. However, it is conceivable that interconnectors could export at times of system stress in Great Britain due to stress events taking place simultaneously in interconnected markets. For example, high pressure systems in Winter, which can cover the whole of North-west Europe, could create widespread high demand for heating at the same time as significantly reducing wind output over periods of up to two weeks. Building interconnectors to a number of different countries could mitigate this risk. Nevertheless, there remains a question about whether the market can be circumvented to stop exports.
2.16 Transmission and System Operators can and do make arrangements in regard to
interconnector flows when needed, as part of the balancing actions they take. However, Energy UK believes that it would be helpful to understand how the use of Public Service Obligations by Governments could be used to influence interconnector flows, and what the impact would be on the resilience of the GB electricity system during a stress event. Such actions would run contrary to the market-based operation of the EU-wide electricity system.
2.17 Investment in networks
Investment into the electricity grid and gas network is vital to support resilience, security of supply and connecting new generation. Up to 2020 there is expected to be significant new renewable generation which will need to be connected to either the distribution or transmission network. The will require a large amount of investment from the Network Operators which will be regulated by Ofgem. A balance must therefore be struck between improving resilience through reinforcement of current lines, new build to reduce congestion on the network and the cost to consumers. The effectiveness and efficiency of the processes governing funding and delivery of new transmission infrastructure should be monitored closely to ensure that needs cases are identified promptly and transparently.
3 How are the costs and benefits of investing in electricity resilience assessed and how are decisions made?
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3.1 The costs and benefits of investing in resilience are determined by a mix of the market
and a framework set by Government or the regulator. For instance, investment in network resilience is regulated by Ofgem, whereas for capacity adequacy the level of resilience is set by Government but delivered competitively by the market.
3.2 The level of capacity adequacy is assessed and determined by the Secretary of State. The Government has opted to set a Reliability Standard, via the Energy Act 2013, which establishes a level of security of supply that consumers are willing to pay for. It should be noted that the ambition being set by the UK Government is not for 100% security of supply in all scenarios as that would be costly to consumers in terms of the backup capacity and extensive balancing tools.
3.3 The Reliability Standard is calculated as a Loss of Load Expectation figure of 3 hours per year in which it has been estimated that the cost of avoiding load shedding is higher than what consumers are willing to pay for. The Loss of Load Expectation is relevant to the amount of capacity that will be procured in the Capacity Market.
3.4 Decisions on investment in transmission and distribution networks are made by the
Transmission Network Operators and Distribution Network Operators. However costs are subject to price controls which are approved by Ofgem. Each investment period lasts for 8 years. Companies undertake a period of consultation as part of developing business plans under each price control. A new regulatory framework for setting these costs has begun to be implemented. It is referred to as RIIO which denotes a Revenue = Incentives + Innovation + Outputs model and applies across all of network operators.
3.5 RIIO is designed to drive real benefits for consumers. It intends to provide the companies
with strong incentives to step up and meet the challenges of delivering a low carbon, sustainable energy sector at value for money for existing and future consumers.
3.6 RIIO also intends to create further benefits to customers through network innovation
competitions and allowances. This has already led to development of smart grid technology and research to reduce streetworks. However, it is too early in the implementation of the price control to assess how successful RIIO will be in delivering on all aims.
4 What steps need to be taken by 2020 to ensure that the UK’s electricity system is
resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
4.1 Electricity Market Reform implements the right framework to drive investment in low
carbon generation and sufficient capacity needed to meet the Reliability Standard. Competition will ensure that the Contract for Difference and Capacity Market are implemented in the most cost-effective way possible for consumers.
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4.2 Electricity Market Reform has cross party support but Government must also ensure that the costs and benefits of policies are honestly and openly explained to consumers, given that the Contract for Difference and Capacity Market manifest as costs on bills.
5 Will the next six years provide any insights which will help inform future decisions on
investment in electricity infrastructure?
5.1 Some key developments and decisions will take place over the next six years which will inform decisions on investing in electricity infrastructure in the UK:
The success of Electricity Market Reform in setting the framework for investment in low carbon electricity generation and backup capacity required to maintain system resilience.
The European Commission’s decisions on 2030 targets. This will include a Green House Gas reduction target and a Europe wide renewables target that will inform national decisions.
Reform of the European Emissions Trading Scheme to establish a robust carbon price will be needed to drive investment in low carbon.
Electricity demand may increase; particularly should the economy continue to grow following the recession. Energy efficiency could help offset an increase in demand.
Increased electrification of transport via electric vehicles and heating however could lead to an increase in demand beyond what is forecast. However, this could put pressure on the distribution networks which are already nearly fully-loaded at times of peak local demand at the lowest voltage levels. Increasing the capacity of these assets would take time. An assumption has been made in the investment plan for DNOs out to 2023 (in “RIIO-ED1”), that the number of electric vehicles before 2023 is modest so an unanticipated surge in take-up could be challenging.
An increase in Demand Side Response initiatives are intended to increase the potential for temporary reduction of electricity peak demand, including via the Capacity Market and Demand Supplemental Balancing Reserve. This could reduce the requirement for additional power stations and use of the networks. Voluntary demand-side response, in response to the electricity price; will be enabled via smart meter rollout and will requires no new payment stream to customers. The smart meters will transmit the Supplier’s live price around the home, and relevant appliances will be able to be programmed to run at times of cheapest tariff price, if the homeowner wishes to. If a home avoids demand at peak price, its bill is lower; the reward is therefore simple, and inherent.
Developments on Carbon Capture and Storage (CCS) will become clearer as the two demonstration projects, Peterhead and White Rose, progress and it is clearer how the CfD for CCS will work. CCS is an innovative technology which will help with the resilience of the system, whilst addressing greenhouse gas emissions as it will enable fossil fuels to continue to be used as part of a low carbon generation mix and will serve as an aid to balance variable forms of low carbon generation.
Medium term (to 2030)
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6 What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
6.1 A greater proportion of intermittent generation could provide challenges to system
operation, particularly as visibility of embedded and small scale generation is limited at present. There will need to be greater flexibility to respond to fluctuations in supply and demand on the system, for example through more flexible generation and increased demand side response, as well as the right trading and balancing arrangements.
6.2 From a generation adequacy perspective, the existing coal and nuclear capacity will close throughout the 2020s so will need to be replaced by sufficient baseload and peaking capacity to support and operate beside the intermittent generation on the system.
6.3 A DECC report from August 2012 sets out the challenges for the electricity system up to
2050 in order to meet carbon reduction targets.55 It sets out that a number of ‘balancing technologies’, namely demand side response, storage, interconnection and smarter networks will need to start being widely deployed in the 2020s. While the majority of the actions in the report have been pursued since 2012, it remains to be seen whether new routes to market, namely the Capacity Market, will help bring these new technologies forward.
8 What steps need to be taken to ensure that the UK’s electricity system is resilient as
well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
8.1 There are some key steps which will need to be taken to ensure that the electricity
sector is largely decarbonised by 2030, although they must be taken in a way that does not adversely affect the UK’s economic competitiveness or make the cost of electricity too expensive for households: Decarbonisation
8.2 Energy UK welcomes the lead which the UK Government has taken in putting the case forward for an ambitious 2030 greenhouse gas reduction target for Europe and stresses the need for early agreement on the high-level objectives. In our view, it is essential to have a clear and stable long-term regulatory framework that will ensure a smooth transition from the 2020 to 2030 objectives and provide the necessary certainty required by investors. Energy UK broadly welcomes the Commission’s proposals, which provide for a binding greenhouse gas reduction target of 40% in 2030 compared with 1990 levels. Care must be taken to ensure the affordability of this European target and to assess its impact on competitiveness. We emphasise the continuing need to conclude an international agreement on climate action in 2015 and strongly support the Government’s efforts in this direction.
55 Electricity System: Assessment of Future Challenges (DECC, August 2012): https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/48549/6098-electricity-system-assessment-future-chall.pdf.
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8.3 A more effective Emissions Trading Scheme is essential for facilitating a cost-effective transition to a low-carbon economy. To provide a stronger signal for investment in low carbon technologies, surplus allowances have to be reduced either by retiring, not issuing or imposing faster and earlier removal from the market. We also welcome the European Commission’s proposition of a Market Stability Reserve provided it can meet the criteria of a predictable and transparent mechanism that is subject to minimal political influence. Energy UK would support advancing its start to 2017 and the immediate transfer of the 900m “back-loaded” Allowances into the Market Stability Reserve .We also support the proposal to increase the Emissions Trading Scheme linear reduction factor from the current 1.74% to 2.2% per year from 2021, to ensure that it is aligned with the likely 40% 2030 GHG target.
9 Is the technology for achieving this market ready? How are further developments in
science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
9.1 There are some technological developments already in train that will assist with
resilience. The rollout of smart meters, for example, will facilitate greater public engagement with energy consumption and in combination with innovative supplier tariffs, such as time of use, should help increase demand side response so that peaks in demand can be flattened out. Smart grids will take this a step further by bringing increased automation to this process.
9.2 If economic electricity storage, able to store large amounts of energy, were developed, it would be a ‘game changer’ in terms of improving resilience, as it would remove some of the challenges related to managing intermittency and reducing the requirement for backup generation and use of the network. This does require a radical reduction in cost and increase in total potential storage scale, whether the storage is deployed in many smaller sites or a few very large ones. So far all of Britain’s electricity storage facilities can store 32 GWh, a small fraction of our electricity demand on a winter day, of 1500 GWh; this is undertaken using pumped storage, as this is the cheapest approach to large-scale storage. In Germany, the figures are comparable (40 GWh of electricity storage capacity overall).
9.3 Changes to the industry codes that govern the granting of access to and use of grid
systems are likely to be required to change, as they do not currently take adequate account of storage. Users of grid systems are categorised as either generators or consumers; storage is neither and the regulated industry codes need to take account of its unique characteristics in order to give it the opportunity to deliver long term benefits to consumers.
9.4 Long lead times also mean that some storage projects (particularly bulk storage) would
have to commit significant levels of capital well ahead of future delivery years, and far beyond development periods recognised under current or upcoming routes to market
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such as the capacity mechanism design. Flexibility within these routes to market is needed to ensure that such issues can be addressed.
12 Is the current regulatory and policy context in the UK enabling? Will a market-led
approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
12.1 Policy and regulatory interventions, where required, to deliver decarbonisation and improve resilience, should be market-based. Electricity Market Reform, for example, should set the right framework for the market to invest in the electricity infrastructure required to deliver resilience.
12.2 Government and Ofgem must ensure that the policy and regulatory framework necessary to deliver resilience solutions such as storage and demand side management is place. This framework should support providers of such new technologies to deliver services that enhance system resilience and deliver value to the consumers. As identified a recent DECC review, more strategic consideration and integrated supply and demand side approach needs to be given to realising the potential benefits of demand side, storage and decentralised generation.56
12.3 Coordination on resilience between government departments and regulators is
essential in order to ensure that policies and regulations align to create a stable and predictable environment for investment.
19 September 2014
56 DECC Review of demand side policy landscape and modelling: https://www.gov.uk/government/publications/review-of-demand-side-policy-landscape-and-modelling--2.
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Professor David Fisk and Dr Deeph Chana, Imperial College London – Written evidence (REI0051) Cyber Security of Low Carbon Power Summary The Committee’s call for evidence noted that the increased complexity of the power grid and networks that might follow from a transition to a low carbon economy could be a route for cyber terrorism. This note underlies that concern, recalls some recent security breaches, and suggests a way forward, driven by the assumption that a cyber attack is not a matter of if but a matter of delaying when. These concerns may not endure forever, but at the moment the state of counter-terrorism technology and the global threats suggests prudence is the wisest course. The Changing Landscape of Energy Security The scenarios typically used in the climate change discourse have little to suggest a world in conflict between now and 2100. While that is a reasonable basis for informing debate, reality is likely to be much messier, particularly as cyber related security issues continue to evolve, forcing reconsideration of conventional definitions of conflict. Generals are famed for preparing to re-fight the last war next, and this is probably also true of energy security. In the 20th century power production was just one of the many casualties in largely indiscriminate aerial bombardment and energy security was an issue of protecting or diversifying supply routes. In the 21st century there has been a significant change. It is now seen as legitimate to ‘surgically remove’ utility infrastructure at an early stage of a conflict, leaving civilians uninjured but in chaos. It is probably not possible to defend energy infrastructure from such attacks, but at least the aggressor is clear. The Committee will wish to consider the possibility that, through technical developments in the grids and networks, the same effect could be delivered in an automated time-controlled fashion, remotely from outside national boundaries and jurisdictions and by complete stealth. These factors not only allow for greater flexibility in the method of an attack, but also augment the attacker’s ability to shape its narrative to achieve a desired impact. Control on announcing responsibility, maintaining anonymity and, most divisively, misattribution are all enhanced. The last of these has the potential of affecting inter-state political relationships, inter-industrial trust and cooperation and complicates the problem of differentiating between accidents and attacks. The Economics of Cyber warfare The asymmetry of cyber aggression is its most worrying aspect. Every day there are stories of successful hacking attacks, but never stories of the successful apprehension of hackers. That is no real surprise since malware is just lines of code scattered amongst millions of others with no trace of origin. But this anonymity means that repeated attacks can be attempted without any increase in the probability of being caught. Media attention has naturally
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focussed on hacking attacks at high profile enterprise systems. The motive for writing the code was financial profit and there was no obvious reason to infect industrial control systems. It was not until the discovery of the Stuxnet attack on the Iranian nuclear programme, that the capability to cause harm in industrial control systems was widely recognised. While hackers had focussed on commercial targets for gain, Stuxnet is widely assumed to have exposed that Governments were prepared to pay to undermine the cyber security of the industrial systems of other states. The economics are clear. A smart bomb costs over $1M and offers only one overt shot. It is delivered from vulnerable military platforms costing more than ten times that figure. In contrast malware can be created with little industrial infrastructure and can hide undetected in a system until, if ever, it is triggered. Cyber Security of Industrial Control Systems Attacks on industrial control systems (ICS) differ in character from those on enterprise software systems. At the heart of the ICS is the supervisory control and data acquisition (SCADA) system, whose panels are familiar from pictures of plant rooms and control centres. Since the 1980’s SCADA system have made increasing use of information technology to communicate between the controller and geographically dispersed controls, themselves now embedding significant computational power. Consequently there are many points of potential entry to a cyber attack and each has to have been correctly installed to maintain integrity, because default user names and passwords are available from manuals on the web. In one recent case the malware was embedded in a component manufacturer’s routine update. While it is possible to envisage scenarios where an attack has relatively benign physical consequences, the more invidious scenarios for SCADA systems are characterised by coincident cyber and physical impacts. The NE US Blackout in 2003, the largest in US history, was something of a simulation run. While triggered by the physical event of a power line failing, its catastrophic spread was entirely due to the SCADA system’s alarm signal being silenced by an accidental coding error that took months to identify. Indeed the original hypothesis was that the system had been infected by the Blast worm. Most of the US substantial expenditure on cyber security for the grid dates from this time. Even if the malware is identified before it causes any harm, it might take weeks to clean, as in the case of the removal of Regin malware from the Belgian Telecoms network this summer. The effective management of such incidents, ranging from pre-assessment of risk to the speedy and efficient execution of recovery, is often hampered by a lack of visibility of the computing assets that might be affected. This can occur due to the absence of mechanisms/processes for drawing together disparate information or simply because complete asset registers and maps do not exist. The rate of growth in the number of computing systems being integrated into energy networks – e.g. smart meters and novel power generation control components – coupled with the growing levels of interconnectivity between utility organisations, exacerbates the growth and persistence of this problem for the industry.
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Energy companies have now become a prominent target. One recent piece of vicious malware is even being called ‘Energetic Bear’. There are also significant issues on the demand side. Work between the Laing O’Rourke Systems Centre and Imperial’s Institute for Security Science and Technology has exposed the vulnerability of ‘demand side’ SCADA systems. These are often running on legacy, unsupported, software platforms, whose errors in configuration can be uncovered by anyone using a web searcher. They are the very type of system that would be expected to take part in automated demand response programmes. Risk Led Design vs Design Led Risk The degree to which cyber security should influence the design of power grids and networks over the next decades will be dependent on the development of capabilities to identify threats and meaningfully quantify their risk. This will enable a greater level of strategy to be employed in directing effort on counter measures and mitigations likely to be of greatest practical use and benefit. This is an area of intensive research worldwide. Imperial, for example, leads a consortium of universities, the Research Institute for Trustworthy Industrial Control Systems (RITICS), which is supported by the EPSRC and UK National Cyber Security Programme. National Grid is a prominent player in CERT-UK. But at the moment the playing field is tilted towards the aggressor, so it is less a matter of ‘if’ than delaying ‘when’. The key principle is to minimise the benefit to the attacker of devising the attack. It follows that cyber security considerations have to be built in from the start and not applied as a late add-on. A 2012 report by the Electricity Networks Association suggests that networks had yet to fully embrace this concept. If a system is internally insecure and only protected from outside then the prize for breaching the ‘barricade’ is very high. Similarly spurious inter-connectivity between systems, provided on a nice-to-have basis should be avoided if possible. The greater the system resilience after an attack, the less the motive there is for the attack in the first place. The ‘internet of things’, which is widely paraded as the future of IT within the home and the city, is unlikely to be secure simply because it has so many access points. But it would not be worth a state’s military exploiting the vulnerability of a smart refrigerator if it were not an access to a bigger prize. In any case while it is conceivable that a single entity like a grid operator or network operator could apply a single security standard, experience suggests this is unlikely to be successful spread over thousands of users. Conclusion The Committee were right to highlight cyber security when referring to the transformation of the grid and networks towards a low carbon future. The cyber security landscape is changing rapidly and it can longer be assumed that attacks would merely be pranksters. At least in the near term cyber security considerations have to be built in from the start. Hopefully this will not be forever. A world able to agree and deliver tough reduction targets is presumably not a world at the edge of all-out cyber-warfare. But until then, prudence is the right policy. 20 December 2014
Flexitricity – Written evidence (REI0058)
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Flexitricity – Written evidence (REI0058) Case Study: New revenue from flexible cooling – Norish and Flexitricity Cold storage and logistics operator Norish is reducing UK carbon emissions while generating revenues from its energy operations, thanks to Flexitricity’s smart grid approach. Norish operates eight storage and distribution centres across England and Wales, including more than 75,000 racked pallet spaces, of which 60,000 are temperature-controlled. The company retains food and related products for its customers at temperatures as low as –29°C. They have four sites connected to Flexitricity’s smart grid and have been earning revenue from Flexitricity’s services since 2008. At times of high national electricity demand, or if a major power station fails, Flexitricity turns down Norish’s cooling plant for short periods to reduce the stress on the electricity network. Critical temperatures are monitored to ensure the integrity of the stored product. This allows Norish to earn extra revenue without disrupting its normal business operations. “In the main, our role is that when the National Grid requires a brake to be applied to energy consumption, we can contribute by reducing plant loading for certain periods without affecting product temperatures or freezing cycles”, commented Norman Hatcliff, Managing Director of Norish. “We maintain the temperature controls that we need, but also cut consumption when required, subject to a pre-agreed maximum duration, during those periods of high demand. “From a practical point of view, Norish engineers monitor our plant at all times. But the whole STOR process is automated and managed by Flexitricity. It brings in revenue to Norish, and allows us to do our bit in reducing carbon emissions.” Flexitricity’s smart grid provides National Grid with a variety of reserve services to help keep the electricity system stable during times of system stress. Norish’s sites provide Short Term Operating Reserve (STOR) capacity, which is one of the most important reserve services utilising fast-acting generation or demand-reduction to respond to periods where there is a shortfall in electricity supply or high electricity demand. Every megawatt of capacity connected to Flexitricity’s smart grid is a megawatt that does not have to be held in reserve elsewhere. This reduces the need to keep coal and oil stations on hot standby or running inefficiently at part load. 6 February 2015
GDF SUEZ Energy UK-Turkey – Written evidence (REI0036)
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GDF SUEZ Energy UK-Turkey – Written evidence (REI0036) (I) Background GDF SUEZ Energy International is responsible for GDF SUEZ’s energy activities in 32 countries across five regions worldwide. Together with power generation, we are also active in closely linked businesses including downstream LNG, gas distribution, desalination and retail. GDF SUEZ Energy International has a strong presence in its markets with 72.9 GW gross (37.4 GW net) capacity in operation and 8.4 GW gross (4.4 GW net) capacity of projects under construction as at 31 December 2013. GDF SUEZ Energy in the UK is the country’s largest independent power producer by capacity with interests in 5,015 MW of plant in operation in the UK market made up of a mixed portfolio of assets – coal, gas, CHP, wind, OCGT distillate, and the UK’s foremost pumped storage facility. Several of these assets are owned and operated in partnership with Mitsui & Co. The generation assets represent approximately 6% of the UK’s installed capacity. The company also has a retail business supplying electricity and gas to the Industrial and Commercial sector. In March 2014, GDF SUEZ acquired West Coast Energy (WCE), an independent renewable energy developer based in North Wales. The company has a wind development pipeline of 500MW, with GDF SUEZ operating 70MW of wind farms in the UK, 50MW of which were jointly developed with WCE since 2008. WCE also has an early stage portfolio of other renewable opportunities, including solar PV and small scale hydro projects. GDF SUEZ welcomes the opportunity to comment on the House of Lord’s Science and Technology Committee inquiry into the resilience of electricity infrastructure. (II) Summary
The UK’s electricity system is less resilient today than it has been in the past. This is evidenced by the level of de-rated reserve margin, which has steadily fallen in recent years. To ensure resilience of the electricity system, a mix of generation technologies will need to continue supplying the UK grid network including a significant level of thermal generation.
There remains the risk that some existing gas generators may seek to close or mothball assets should plant be unsuccessful in obtaining a 1-year contract from the capacity mechanism. This is especially the case as gas generators have recently incurred large losses as spark spreads remain very low. If this issue is not addressed, there may well be plant closure, threatening security of supply, system resilience, and increasing the cost to the consumer. This could be an unintended consequence of the first auction of the enduring capacity mechanism scheme, and the use of the Supplemental Balancing Reserve should not be seen as a solution to avoid potential closure.
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Government has indicated the path of travel for the electricity system, with EMR expected to deliver certain outcomes. When the mechanisms introduced through EMR have bedded in, industry will require a period of stability with further interventions restricted, whilst ensuring transparency of process and equal treatment for all industry participants.
To ensure open competition across all sources of generation, renewables will need to reach a level of technological maturity. If this level of maturity is not reached during the next decade (including Carbon Capture and Storage) it will be necessary to ensure adequate thermal generation exists to fill gaps in supply, in response to intermittent generation, and to help to maintain system resilience.
The UK no longer has a fully liberalised market, and administered strike prices for less established technologies under CFDs illustrate this. The UK is entering a period whereby a managed market will prevail with some aspects of a liberalised market being retained, and industry stakeholders will have to engage with this structure.
The UK government should avoid picking ‘technology winners’. Renewable technologies should be encouraged along the learning curve before competing with other, lower cost renewable technologies (for example, in the case of solar PV being included in the same CFD category as onshore wind). Recent political interventions aimed at limiting the role of onshore wind and solar PV have not been helpful.
Measures are in place to enable government and industry to learn from research and development of demonstration projects. Examples include £1bn of funding to two Carbon Capture and Storage projects, and R&D in other low carbon generation technologies, notably tidal and wave power, through the development of demonstration projects.
(III) Answers to Questions Question 1 – How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base? 1) The UK’s electricity system is less resilient today than it has been in the past. This is
evidenced by the level of de-rated57 reserve margin, which has steadily fallen in recent years.
2) This compares to the historic record of the system, which has shown resilience to
movements and peaks in consumer demand and sudden shocks. No nationwide period of ‘blackout’ or ‘brownout’ has occurred in recent times. This has largely been attributable to the level and mix of power generation available to meet growing demand (power plants with fast response times), but also to effective management of the grid network by the system operator.
57 The excess of available capacity over winter peak demand.
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3) Future resilience of the system relies upon a number of drivers, particularly the level of reserve margin across the UK network. The UK is currently experiencing one of the lowest levels of reserve margin. This has been exacerbated by the closure of ageing coal plant under the Large Combustion Plant Directive (LCPD)/Industrial Emissions Directive (IED), the ageing nuclear fleet, and by challenging market conditions for gas-fired generation.
4) The level of de-rated reserve margin has declined recently following the withdrawal of
coal, nuclear and gas plant from the system. However, when looking at the de-rated reserve margin by itself it is necessary to understand the types of generation technologies that contribute to it, and how much of this is firm rather than intermittent or variable generation.
5) The use of Ancillary Services in the UK wide market has also contributed to the resilience
of the system. The system operator’s ability to call upon fast response or back-up generation to meet peaks in demand, or sudden shocks, has played a key role in ensuring the frequency of the network has been maintained, and that lights have been kept on. The need for greater use of ancillary services is likely to grow in the future as more intermittent forms of generation are built.
Question 2 – What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’? 6) Absent perverse outcomes, the measures undertaken by government may be sufficient
to ‘keep the lights on’ after the onset of the enduring capacity mechanism in 2018.
7) The capacity market is expected to help recover the fixed costs of generation, which is particularly helpful to gas generators at a time when spark spreads remain weak in forward markets. The gas sector has incurred significant losses over the last few years, and is expected to make further losses should forward spark spreads fail to improve. There is concern that the scale of potential losses has not been anticipated.
8) There remains the risk that existing gas generators may seek to close or mothball assets
should plant be unsuccessful in obtaining a 1-year capacity contract. This raises the question as to whether gas operators will be able to keep plant open a further five years, with potential losses being made, without the availability of a capacity contract in future. This could be an unintended consequence of the introduction of the capacity market mechanism, and could therefore have implications for system resilience in the short term.
9) If this issue is not addressed, there may well be plant closure, threatening security of
supply and increasing the cost to the consumer. The existing gas generators of the Independent Generators Group have already urged the Government to take action.
10) Government has also introduced the Supplemental Balancing Reserve (SBR), a
mechanism designed to allow the system operator to contract capacity in the short-term to help cover any periods of low reserve prior to commencement of the capacity market.
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GDF SUEZ opposed the introduction of the SBR, as the company felt it provided the wrong signals to the wider market – that is, it provides mothballed plant with a benefit which other plant, continuing to operate in the market, will not receive.
11) The UK network is also interconnected to nearby markets, and has the option to import
electricity if needed at times of peak demand. Interconnections exist with France, the Netherlands and Ireland, for a total capacity of 4GW. Future connections are also planned between the UK and Belgium (1GW, 2018) and to Norway (1.4GW, 2020). Such connections will help to improve the resilience of the UK through the provision of greater diversity of supplies.
12) However, it is important to note that such diversification will only be available if
connected markets are able to provide excess supply to the UK when it is needed (that is, at times when supply is not required by connected states). In addition, it is unclear whether interconnectors will be able to provide supply over extended or prolonged periods of time. This will need to be carefully considered when assessing the future resilience of the electricity system. Finally, interconnectors are expected to participate in the capacity mechanism from 2015. For interconnectors to contribute to system resilience, safeguards will need to be considered such that capacity market contractual terms exist in both the UK and in the country the interconnector is linked to.
Question 3 – How are the costs and benefits of investing in electricity resilience assessed and how are decisions made?
13) Through the introduction of EMR, the government has stated its desire to ensure the continuation of a competitive market, based on bilateral trading, a capacity mechanism, and contracts for difference (CFDs) for low carbon technologies. In each of these areas costs and benefits of investment are considered by operators or developers of generation and transmission, and a financial return sought on projects.
14) Both government and the system operator have roles within each of these mechanisms. For example, government sets expenditure on low carbon technologies through the Levy Control Framework (LCF), and ensures that annual expenditures on the Renewable Obligation (RO) and CFDs do no breach set LCF budgets. For ‘established’ low carbon technologies, government has set up a competitive system through which developers submit bids based on required strike prices, at which point an auction is run and the most competitive bids selected up to the level of budget for that category. For ‘less established’ technologies, projects are selected based on a set criteria rather than a competitive bidding process, where costs and benefits are assessed on project financing, contribution to economic development, and project timetable.
15) The capacity mechanism also allows for the costs and benefits of bids to be considered through a competitive auction process, thereby ‘costing-in’ security of supply into the system. Government has established a Reliability Standard, which sets a security of supply level affordable to the consumer. This is based upon a Loss of Load Expectation level of 3 hours per year in which the cost of avoiding load shedding is higher than the level consumers are willing to pay for. This helps to inform the decision making process with
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regard to the capacity mechanism, and how much capacity is sought in a particular bidding round.
Question 4 – What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable, and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? 16) The UK is currently on a path to meet its 2020 renewable targets for the electricity
sector. Should it be successful in reaching its targets, then the UK would be in a better position to move along the path towards decarbonisation in 2030.
17) Government is seeking to reach 2020 targets through the introduction of EMR, where
CFDs will incentivise low carbon technologies, and the capacity mechanism will provide for adequate generation to maintain security of supply and system resilience.
18) However, it is important to facilitate a transparent market, with low risk of regulatory
uncertainty, so that investors are willing to invest capital across the network. For this to happen, governments must seek to limit the level of future state intervention which gives rise to increased regulatory uncertainty. In both the short and medium term, a political consensus is required that allows an agreed view to develop on how the market should operate in the future. Without such consensus, the risk of intervention remains, investment may fall, and resilience may therefore be undermined.
19) To continue on a trajectory to decarbonisation, governments need to ensure that both
the RO (up to 2017) and CFD mechanisms function transparently, and remain supported financially, to attract low carbon investment. Governments should resist any urge to intervene in both systems, unless it becomes absolutely necessary to do so from a budgetary point of view. Above all, governments must ensure the principle of ‘grandfathering’ remains, as this forms a significant part of the decision making process by developers seeking to invest in low carbon projects in the UK.
20) Government priorities over the last decade have concentrated on decarbonisation of the
electricity sector. Historically, affordability and security of supply have come after decarbonisation as priorities. Affordability has risen up the political and public agenda recently, and this will require future governments to extend the LCF post 2020 so that costs to the consumer from low carbon technologies are bound.
Question 5 – Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure?
21) GDF SUEZ believes that the EMR process will continue to deliver the required transition
to a low carbon economy, and will provide learning opportunities that will help inform future decisions. Such opportunities will likely focus upon types of technology deployed, lessons of a ‘managed’ market, and government interaction with industry (in terms of consultation and response to proposals).
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22) If the capacity market is successful in bringing on required generation, and maintaining security of supply, then governments are more likely to continue it in future as a way of ensuring system resilience. Furthermore, should the CFD mechanism provide for projects that are delivered to time, and to help meet 2020 targets, then it could form the basis of a future structure for incentivising low carbon technologies onto the UK grid network.
23) Future decisions will also rely on the outcome of current discussions on 2030 environmental targets, in particular those set by the European Commission. Current discussion concerns whether there should be a renewable target, or carbon target, or both for 2030. In addition, discussions concern the level at which 2030 targets should be set. Final agreement on environmental targets for 2030 will help influence the mechanisms, and policy intent, of future governments. For example, under a carbon target for 2030, would a future government turn more towards nuclear generation than renewables? If a renewable target was set for member states, would the opposite view arise?
Question 6 – What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience? 24) Intermittency is likely to grow in the next decade, particularly as levels of supply from
intermittent renewables (such as wind) increase. This presents the challenge of ensuring flexible generation exists that can rapidly react to higher levels of intermittency. In future, the system operator will need to manage large flows of intermittent and variable generation, which have already increased significantly over the past decade and are expected to increase further by 2020, as the chart below illustrates58:
25) Gas generation is one technology that can provide a response to rapid changes in supply
caused by higher levels of intermittent generation. However, other technologies and measures exist, including greater use of demand side response, and the development of
58 Data sourced from Dukes Energy Statistics 2012, and DECC Statistical Press Release, 27th March 2014.
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storage installation both at transmission and distribution levels. No technology or approach should be considered as able to provide the required level of rapid response by itself.
26) Tensions between security of supply and decarbonisation of the electricity sector could also affect system resilience. This will be the case if 2030 decarbonisation targets are stringent, thereby calling for more low carbon generation to be built on the system. However, the successful development of Carbon Capture and Storage (CCS) will help mitigate this risk, and allow firm levels of thermal generation to continue whilst meeting decarbonisation requirements.
Question 7 – What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? 27) Modelling is good at reflecting past outcomes, but is clearly more difficult in forecasting
future trends. In future, modelling of the UK system will need to consider the impact of intermittent generation, and not just firm, thermal sources of supply. This will make modelling more complex, and this will be further complicated by the interaction of transmission connected capacity and localised generation (which is expected to grow in both the short and medium term).
Question 8 - What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? 28) Ensuring a resilient system that is competitive and decarbonised by 2030 will be
influenced by environmental targets for the end of the next decade. Clear targets will be needed so that investors have foresight of how the UK seeks to decarbonise the electricity sector over the next 16 years.
29) In terms of the necessary steps, GDF SUEZ believes requirements include: a. Future commitment to the LCF – that is, beyond 2020, providing investors with
the assurance that future support for low carbon technologies (including nuclear) will be available. Continuation of the LCF would help to bound costs for consumers.
b. Long-term political consensus on the future of the electricity market – such a consensus needs to be developed to ensure certainty for investors, and hence continued investment across the sector. At present, energy remains a highly political issue, and whilst the main parties agree on EMR and the mechanisms it introduces, there remain differences of view over the future regulation of prices, structure of the wholesale market, and the future of vertical integration in the UK. To ensure investor confidence remains, and therefore investment in system resilience continues, a political consensus needs to be developed and maintained.
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A long-term commitment also needs to be made to the capacity mechanism to ensure investment in existing plant and new-build as needed.
c. To ensure open competition across all sources of generation, renewables will
need to reach a level of technological maturity. If this level of maturity is not reached during the next decade (including CCS) it will be necessary to ensure adequate thermal generation exists to fill gaps in supply, in response to intermittent generation, and to help maintain system resilience.
d. The EU Emissions Trading Scheme (EU ETS) remains a fundamental instrument to
encourage low carbon investment, and to this end GDF SUEZ supports its reform, the principle of back-loading, and the early introduction of the Market Stability Reserve. All of these are necessary to ensure progress towards decarbonisation in 2030.
e. It is vital for governments to ensure that UK industrial competitiveness is not adversely affected by maintaining system resilience and the drive towards a low carbon economy.
Question 9 – Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? 30) Some generation technologies already exist, or are in development, to help maintain
resilience against intermittent generation. For example, some manufacturers are designing turbines that will be able to run flexibly in future, such as GE’s FlexEfficiency 50 CCGT designed specifically for variable loads and operating conditions. When commercially proven and available, such designs will allow gas generation to respond to more volatile demand and intermittent supply in power markets. Furthermore, should CCS technology become proven and commercially available next decade, then this will assist the UK in reaching 2030 environmental targets, whilst allowing for such flexible thermal plant to operate on the system.
31) There is evidence to suggest that costs of low carbon technologies are steadily decreasing, and this is borne out by the expectation of future strike prices available through the CFD mechanism. Government’s recent consultation on financial incentives for solar generation points to ongoing reduction in costs, and in recent years the capital cost of both offshore and onshore wind in the UK has fallen. This indicates falling costs in such technologies as the UK addresses greenhouse gas emissions.
32) In terms of game changing technologies, development of electricity storage would provide a major contribution to system resilience, particularly at peak times or during periods of sudden shocks or swings in intermittent type generation. Large scale demand side management would also contribute to maintaining resilience across the network.
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Question 10 – Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
33) The UK is in a position to lead in certain technology areas, particularly those that suit the
country’s natural resources. For example, the UK has over half of global offshore wind capacity installed around its shores. Should other countries wish to develop offshore wind industries, and with continued support by government and industry, this could be a potential driver for economic growth and allow the UK to become a leader in this technology. In addition, wave and marine technologies remain in development, particularly in Scotland, which could also help drive growth, increases in skills, and supply chain development.
34) The UK is also promoting development of CCS technology, through £1bn of funding to
two projects. Should these developments prove successful, the UK could become a world leader in this type of technology.
35) GDF SUEZ believes the UK government should avoid ‘picking technology winners’ and
encourage all technologies further along the learning curve. Allowing technologies to compete against each other will ensure the lowest cost to the overall system, which ultimately will ensure affordability and lowest cost to the consumer. However, there should be a transition to competition amongst renewables as at present some technologies have further to go along the learning curve than others. For example, under the CFD mechanism solar PV has been allocated to the same category (established technology) as onshore wind, with both technologies competing against each other based on price. This is likely to disadvantage solar as costs for that technology remain above onshore wind and are likely to do so in the short term. In this particular case, solar PV should be allocated to the less-established technology category where contracts will be administered rather than allocated on a competitive basis. This will allow developers of solar PV to reduce costs, and look forward to solar competing against other technologies towards the end of this decade.
Question 11 – Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects? 36) GDF SUEZ believes measures are in place and this can be evidenced from development of
particular projects in the UK. For example, the commitment by government to provide £1bn of funding to two CCS projects demonstrates its aim to develop and learn from this new technology, particularly at a time when other projects have been put on hold (such as the Rotterdam Capture and Storage Demonstration Project, ROAD, in the Netherlands).
37) Furthermore, government has sought to increase research by promoting technologies
such as offshore wind, a ‘large-scale’ already deployable source of generation where considerable learning is still to be had (as evidenced by government’s view on costs of offshore wind declining in future). Government has also encouraged R&D in other low
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carbon generation technologies, notably tidal and wave power, through the development of demonstration projects, particularly in Scotland.
Question 12 – Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? 38) The UK no longer has a fully market led approach, and administered strike prices for less
established technologies under CFDs illustrate this. The UK is entering a period whereby a managed market will prevail with some aspects of a liberalised market being retained. Industry stakeholders will have to engage with this structure.
39) The electricity sector has recently experienced a period of profound regulatory change.
Through the introduction of EMR, the UK has sought to establish a system that maintains adequate levels of supply, whilst increasing the level of generation from low carbon sources. To this end, the Energy Act 2013 enables investors to take part in these mechanisms and consider investing in the UK electricity market.
40) This has been further evidenced from the introduction of the FID Enabling regime, where
the number of projects seeking an Investment Contract in Phase 1 was in excess of the number of projects being sought by government.
41) In terms of coordination, this will need to take three forms: firstly, government and
public opinion (where government needs to explain the regulatory context and seek support for future polices); secondly, government and officials (setting the future regulatory framework); and thirdly, government and industry (where industry is free to compete and invest, with minimum regulatory uncertainty).
September 2014
Professor Jon Gibbins, University of Edinburgh, Dr Keith MacLean, University of Exeter and Professor William Nuttall, Open University – Oral evidence (QQ 91-101)
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Professor Jon Gibbins, University of Edinburgh, Dr Keith MacLean, University of Exeter and Professor William Nuttall, Open University – Oral evidence (QQ 91-101)
Evidence Session No. 8 Heard in Public Questions 91 - 101
TUESDAY 18 NOVEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Baroness Sharp of Guildford Lord Willis of Knaresborough
__________________________
Examination of Witnesses
Professor Jon Gibbins, Professor of Power Plant Engineering and Carbon Capture, University of Edinburgh, Dr Keith MacLean, Honorary Fellow of Energy Policy, University of Exeter, and Professor William Nuttall, Professor of Energy, Open University
Q91 The Chairman: Welcome to the second session. I know you are familiar with what we are doing and, indeed, I think you heard some, if not all, of the previous session. As before, I am going to ask if you would like to introduce yourselves for the record, and if any of you would like to make an opening statement, then please feel free to do so. Can we start with Professor Gibbins?
Professor Gibbins: Yes. Jon Gibbins. I am Director of the UKCCS Research Centre, which is a body funded by EPSRC and DECC to be the focal point for academic carbon capture and storage research in the United Kingdom.
Dr MacLean: I am Keith MacLean. I am recently retired after 20 years working in the energy industry. I am now working as an independent energy adviser. Alongside the DECC chief scientific adviser, I also co-chair the Energy Research Partnership, which is a joint public and private sector organisation that looks at prioritising the spend and funding of energy research and informing energy policy on the basis of the R&D work that is being done.
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Professor Nuttall: Good morning. Thank you. I am William Nuttall. I am Professor of Energy at The Open University, where I am based in the Engineering and Innovation Department at our central campus in Milton Keynes. I did have some opening remarks. Should I move on to them?
The Chairman: Please do, yes, fire ahead.
Professor Nuttall: Okay. First of all, I should say that I give my evidence today in a personal capacity and therefore the views I express are not necessarily shared by the numerous institutions I am affiliated with. Yes, the standard thing.
In my opinion, concerns regarding electricity security have evolved over the last 40 years and originally centred upon primary fuel security. I am thinking of access to coal during the miners’ strikes or, more importantly, to imported natural gas. After electricity market liberalisation in the early 1990s, concern increasingly turned to the question of generation adequacy and whether we had enough power stations, and this is still very much a concern. There has been much interest in the extent to which renewables meet that challenge of generation adequacy.
However, to my impression, the issue of current and emerging concern is short-term grid stability, especially if the system were to comprise a very large proportion of renewables. The old paradigm of a hundred or more large thermal generators had an inbuilt stability in the high-speed, synchronised rotation of the heavy metal turbine shafts. If one generator were to go offline, the energy shortfall would immediately be taken from the rotation of all the others. They would slow down, the frequency of the electricity generated would decrease slightly, and this was entirely passive. A future system without such inertia—where on a solar cell things do not rotate at all—could be less robust, I suggest.
Among many duties I have, one is to be a member of the scientific advisory board of an EU Framework 7 project, Sesame, and I should stress the work is done by others. It concerns threats to the electricity system, and I commend its outputs to you. Their work stresses that the threats divide into two types, which are in turn subdivided: on the one hand, traditional or conventional threats—natural events and disasters or accidents—and the new or unconventional threats of malicious threats, including terrorism, or the emerging threats of system vulnerabilities inherent in our new infrastructures and new infrastructure interdependencies. Importantly, they say threats of all types are growing and are still dominated by the conventional threats. Today, only 3% of incidents are malicious and only 3% are emerging, but those elements are growing. I concur with Sesame researchers on most things, but I disagree with them when they posit that electricity market liberalisation has itself been a threat to resilience. I would not go that far, but I would merely agree that it has eroded generation adequacy, but arguably capacity margins were too high in the old days of the CEGB.
Of the various electricity generation technologies with which I am most familiar, nuclear power stands out. I regret that I am insufficiently expert to offer much useful comment at all on carbon capture and storage, but I see you have that sorted out. I will be pleased to supply the Committee with scientific papers relating to my remarks today, and I should stress that my remarks are in many cases based on the work of others.
The Chairman: Thank you very much. Unless there are any further statements, I am going to ask Professor Manningham-Buller if she would like to start the questioning.
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Baroness Manningham-Buller: Thank you for calling me professor.
The Chairman: Sorry, Baroness. Well, you are very nearly, are you not?
Q92 Baroness Manningham-Buller: Not at all; BA, second class. Professor Nuttall gave us some of his views on the resilience of our electricity supplies. I would like to ask Professor Gibbins and Dr MacLean whether you agree or have anything to add or have a different perspective on the risks to the resilience of our system.
Professor Gibbins: Okay. I will go first, if that is all right. I should also say I am speaking in a personal capacity here. I will look at the longer term, and one thing I am seeing is that I think privatisation and subsequent developments have eroded a lot of utility confidence in knowing what is going on. I am dealing with utility companies that are considering building gas plants, unabated and with carbon capture and storage. What they say is, “We really do not know how much we will be able to run in five or 10 years’ time because it is going to be governed by how much wind is subsidised or incentivised on to the market”. There is a great deal of uncertainty there when you are building conventional plant, and I suggest that we are moving to a market that is basically subsidised electricity generation. One of the problems will be deciding which of those subsidised or incentivised, whichever you want to call it, generators does not run when we have excess supply, and then also deciding how anything but incentivised or subsidised electricity will be available to run at periods of high demand.
We are moving into very much a control situation. The ability of the market and the confidence of the market to predict shortfalls in supply and to build plant to meet those shortfalls has been eroded because of the total unpredictability of what the shortfall will be and how it will arise due to the incentivisation of mainly intermittent wind.
Dr MacLean: I would agree with a lot of what has been said and, clearly, the challenges on system adequacy are only going to increase. The Government itself has recognised that and has put in place the capacity mechanism, alongside many other mechanisms it has given itself to try to intervene in order to make a difference there. As a mechanism, it has the potential to encourage sufficient investment in capacity to deal with the sorts of issues that the others have mentioned.
There are other aspects to system resilience. Often neglected but often the most common causes of interruptions are, indeed, the supporting infrastructure, in particular the distribution networks. Therefore, we need to be very careful in the investment programmes we are carrying out that we make sure that there is sufficient clarity about what needs to be done in order to develop the distribution and transmission networks or, indeed, other supporting infrastructures in order to be available on time and in sufficient quantity to deal with the consumption and production requirements that we have. Remembering as well that infrastructures often take much longer to develop than the consumption or production devices that they join up, we must be much clearer than we are at the moment about what it is that we are trying to do, otherwise we will not be able to put in place the supporting infrastructures.
Therefore, alongside the technical questions that the Committee is asking, I think it needs to look very much at the organisational and administrative elements of that. As Professor Gibbins has said, we now have a situation where the Secretary of State probably has far more powers to intervene than he ever did in the days of the CEGB. We are more in a central
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planning world than we ever were in the CEGB, except we do not now have an explicit plan. We do not have an explicit organisation that counterbalances the views of the Secretary of State. I think the Committee should also ask whether we have the institutional competence in DECC to be able to carry out all of those many powers that they have now given themselves over the years.
Q93 Baroness Manningham-Buller: Let us ask that. We have had three comments from you: one on less robustness, Professor Nuttall; uncertainty; greater centralisation, and your contribution saying that we have to challenge Government more. What recommendations should this Committee be putting to Government on how to reduce or manage the risks better or differently?
Dr MacLean: I think we need to get away from the pretence that we have a market-led system and that the market is going to decide. We need to call a spade a spade and say the decisions are being made centrally. Once that is done, it is then perfectly possible to allow the private sector to deliver, and the private sector is very good at delivering when it is given a clear task. The Olympics was a classic example. There was a central decision made where we were going to do something, when it was needed, what it was, and then we let people get on in the private sector to deliver that, and it was successful. At the moment, we do not have that clarity about what we need for what is a very important aspect underpinning so much else of the society that we need. It seems quite strange that we do not have a clear plan, a clear vision of what it is that we are trying to create, or a pathway for how we are going to get there. My one recommendation would be let us have an explicit plan, and if the Secretary of State does not want to do it, then he needs to nominate some one organisation very clearly to do it for him.
Professor Nuttall: To answer your question, what I am about to say may sound like I am against renewables, but I am more against renewables policy—there is a distinction. I think also that in the policy framework, at least philosophically, we are a long way from where we should be. I note that in their written evidence—it was the answer to question 9—Ofgem asserts that it is technology neutral. Yet, of course, in our energy market special status is given to renewables. One might ask why, but that is too much of a digression, I think. Until EMR, at least, the UK operated an energy-only market and each kilowatt hour was regarded as equally valuable. Renewables were subsidised in addition by renewable obligation certificates.
To answer your question, I posit that we should incentivise reliability and we should incentivise low carbon and otherwise be utterly technologically neutral. I could say a bit more if you are interested.
Professor Gibbins: To answer that particular question, one thing that I think should be done is that much more emphasis is placed on system-wide evaluation rather than looking at individual technologies, because we have seen too much that one particular technology gets subsidised without any consequence at all for what happens elsewhere. That gives a very false impression of the cost, and also the overall system robustness. Obviously, somebody then does need to be responsible, and I would second this one that there has been a mantra, “The market will decide”. In other words, the Government does not have to take responsibility, but it does. The buck will come home eventually to the Government if we start to see problems with electricity, clearly.
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Lord Peston: Just to get it clear, the three of you are scientists and technologists, is that right, but included in the science and technology you know is an understanding of systems theory?
Professor Gibbins: Yes.
Lord Peston: All right. So I know who I am talking to. You are being asked questions by an ignoramus. I can get as far as the on-off switch, but not much further. What interests me—and your point, Dr MacLean, particularly interested me—is that you wanted a clear-cut set of objectives, is what you said. Would I be right, placing this into perspective, that one of our problems is that there are two kinds of objectives here, cheap electricity on the one hand and a desire not to intensify the climate change problem? Dr MacLean, did you tell us who could give us the answer to that balance? You said you wanted objectives.
Dr MacLean: Yes. I think that at the moment it is very clear that all of those powers sit with the Secretary of State or with his colleagues around the Cabinet table. There is a reluctance, as I say, to make the decisions and I do not know necessarily whether that is a reluctance to take responsibility, and therefore potential blame, if it did go wrong, or whether it is simply the competence issue that I mentioned, that there is not sufficient competence within the department or departments to allow that to happen. These sorts of tradeoffs are classical political issues that the market simply cannot decide. We did ourselves a disservice in many respects in the mid to late 2000s where we quite rightly decided to address the climate change issue, but we forgot to work out how much it was going to cost and who was going to pay for it. That is simply the point that I am making, that we need to have a clear approach that is costed in a way that everybody knows what they are embarking upon and, therefore, that they do not need to change direction all the time because they are not going to come across surprises or changes in direction of policy, which is what we have seen on a very regular basis.
Professor Gibbins: If we look at what is happening now and what is going on, in some respects DECC deserves quite a big pat on the back for pushing, at the European level, a carbon emissions target for 2030, not a renewables target. We have to look at the 2020 targets through a legally binding obligation to get, I think it was, 14% of UK energy from renewable sources, a lot of which was done or is expected to be done through the electricity sector. You cannot expect DECC to do something that will knowingly get below that target. You can argue why the target is there. It should not be there, I would say, but it came first. It came for different reasons. You have to recognise that the mindset of a lot of people on the environmental side, if you like, is focused back to the oil crisis and that the problem is we are running out of fossil fuels. The climate problem is we have far too much fossil fuel. We are trying to deal with today’s problem with yesterday’s technology. But to give DECC credit, and they have to take a lot of the credit for this, they have seen that by 2030 we will be looking at the real problem, which is carbon, and the renewables target I do not think will bite too hard on the UK.
Q94 Lord Peston: May I just make a minor point to support you but then get on to my main question? When I first worked at the Treasury, working on the economics of all this, the one thing that never occurred to us is that there would be an oil problem. That never entered into our calculations. Typically, the main thing that happened was what happened. Can you clarify the technology for me? The point about many of the renewables is that they are intermittent—that is the main thing about them. Do we have the technology to offset the
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intermittent nature of that, and, therefore, is the only question one of cost? Or do we not even have the technology to offset the intermittent nature of some of the renewables?
Professor Gibbins: Yes, we do have the technology. The issue is one of cost. Let me just back up one more. When we had a 60% target for 2050, if you go back maybe, I do not know, 10 years, that 60% reduction in the emissions target could be met by what I call the “gas and wind” model, which is basically you have wind and unabated gas filling in the gaps, basically, and that worked. When you are looking for 80% reduction and now, from the latest IPCC recommendations, eventually zero emissions, you have to have something that does not emit CO2, so CCS plant if you are using fossil fuels or relatively expensive storage. You can do it, but then you will say, particularly if you have a CCS plant, why was I not using that plant all the time? I have turned it off. I have forgone—when I turn off a gas plant so I can run a wind plant—some very cheap electricity. It is available at the marginal running cost of that plant. Yes, you can do it. It costs money.
We had a presentation yesterday in the Centre from George Day at ETI, and ETI’s prediction is that by 2030, if you did not use CCS and you did it all with renewables, you would be costing maybe of the order of £10 billion extra a year to the economy, and that would increase into several tens of billions by 2050.
The Chairman: Just to recap at this stage, we have recognised that we do have the technologies but they are expensive, and the higher you ramp up the target, the higher the cost is going to be.
Professor Gibbins: Sorry, if you do not mind me saying, we do have the technologies. They are expensive in the sense that not doing anything about cutting CO2 emissions arguably would save you less money in some short-term sense. But there are ways to meet low-carbon objectives and eventually security objectives that are more or less costly depending on the option, the mix of technologies that you take.
Q95 The Chairman: One of the options, clearly, is CCS. If we are awash with fossil fuels, certainly with gas as we appear to be, and if you can effectively undertake carbon capture and storage, including the transportation, then that would clearly be an interesting option. You heard in the earlier evidence there was some degree of cynicism about when this is going to be deliverable on a commercial scale. What are your thoughts on that as to how probable it is that we can see retrofitting of CCS on to existing power generation using fossil fuels?
Professor Gibbins: I think it is entirely probable because we have seen the first coal-fired power plant with carbon capture and storage running in Saskatchewan. I was there myself a couple of months ago at the opening. It is now running successfully. It was built on budget and pretty much on time. That technology, with some modification, is being proposed for a retrofit on a natural gas-fired power plant at Peterhead. It is exactly the same supplier, Shell Cansolv, so that is arguably somewhat of a second generation plant, although it is modified a bit to go on gas.
The technology that is being proposed for the White Rose project in Yorkshire is well-developed and understood. It is based to a large extent on conventional pulverised coal technology. We are also seeing gasification-based projects, admittedly at fairly high cost, being started in the United States that will, I am sure, operate. The technical barriers are not very great.
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I think we have all the elements there. There are probably three commercial suppliers, with very, very strong technical backgrounds, commercial backgrounds, that would give you post-combustion plant for natural gas with commercial guarantees right now. I think that is perfectly available.
The UK has the leading CO2 storage assets offshore in Europe. We have a lot of good power plant sites on the East Coast that can be developed. Ultimately, the geography of those sites and the geology in the North Sea may be worth at least as much to the UK as the offshore oil and gas that we had. If you are taking a decarbonised future, then being able to avoid your emissions at low cost, both for power and indeed for industry—and steel manufacture and cement manufacture are areas where you cannot do anything else but carbon capture and storage of emissions. Taking that forward, we could well see that the UK and the UK East Coast becomes an industrial heartland for Europe because it can do it in a low-carbon way.
Lord O’Neill of Clackmannan: What is the lifetime of a gas plant, a gas-fired power station?
Professor Gibbins: It is probably about 15 to 20 years, and then you would look to upgrade the turbines, replace the turbines.
Lord O’Neill of Clackmannan: You have quite sizeable capital expenditure.
Professor Gibbins: Yes.
Lord O’Neill of Clackmannan: If you are retrofitting, you are reducing the efficiency of the plant by the CCS.
Professor Gibbins: Yes.
Lord O’Neill of Clackmannan: The electricity will become more expensive for two reasons.
Professor Gibbins: Yes.
Lord O’Neill of Clackmannan: You are still telling us that it is going to be economically viable on a plant that only has 15 to 20 years of life to start with. To be honest, the economics sound incredibly shaky. You are talking as an engineer in love with the technology. You are not telling us, really, how much it is going to cost and how viable it will be. All you are telling us—
Professor Gibbins: Can I tell you something? I will tell you straight. If you do this, you will only do it because it is economically viable. Engineers are pretty hardnosed. People are not going to do this for the beauty of the technology beyond the first few demonstration units. Clearly, you seem to be positing a counterfactual where we have to do nothing.
Lord O’Neill of Clackmannan: No, I am not. I am merely saying that you are positing a solution where, at the moment, you have not given us sufficient financial evidence to suggest that it is attractive and likely to be worthwhile.
Professor Gibbins: Compared to what, though? That is the point. You want to have—
Lord O’Neill of Clackmannan: Compared to, perhaps, taking a hit in the short to medium term on using more gas and accepting that it is dirtier than you would want it to be.
Professor Gibbins: Look, if the UK has international obligations to cut its CO2 emissions, it will have to do that.
Lord O’Neill of Clackmannan: It is not doing it at the moment when it is burning more coal than it should be.
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Professor Gibbins: The UK is meeting, I believe, its international CO2 targets, and it will certainly do its best to do so. There is a bit of a red herring there. When we burn coal we are burning it under the EU emissions trading cap. The UK counts its national emissions as its cap, so whether we cut emissions or not, our emissions are what we are allowed under the trading cap. That is the purpose of a trading cap.
Q96 The Chairman: Could I come back to the record of CCS in this country?
Professor Gibbins: Yes.
The Chairman: We had written evidence from the Carbon Capture & Storage Association, which of course, as you would expect, see this as an important development, as I think many of us would if results so far had not been rather disappointing. I read from their evidence. They say, “The development of projects has not progressed as quickly as anticipated and the first operating power CCS projects are in North America. UK industry has taken around 17 projects to various stages of development and it is deeply disappointing that progress here has not been as rapid as expected.” Would you think that was a fair comment and what would you attribute that—
Professor Gibbins: No, I do not think that is a fair comment. I think they are an industry association that has to put forward fairly strongly what is going on, but I would say in defence of the Government and policy that the story is this: in 2005 Lord Browne from BP proposed a CCS project at Peterhead to back up the UK’s initiative as part of the Gleneagles summit on climate change. Very effectively, it put CCS on the map. That project was technically unambitious, but perhaps reasonably so because it was first of a kind. It was precombustion; that is, producing hydrogen from natural gas. The project progressed through FEED study and got to a reasonably advanced level, and then the economics of the electricity industry meant that the utilities very seriously proposed building about 10 major new coal-fired power plants. The first one of those that was proposed was at Kingsnorth and, if you remember, there were climate camps, there were protests. The roof of the hall here was covered by Greenpeace protesters at one stage. There were pickets around Ratcliffe. There were disruptions to supply. There were all sorts of things going on.
It was not possible at that time to say, “Oh, do not worry, we will sort out CO2 emissions from coal. We are doing precombustion on gas”. The technology was inappropriate. So we then moved into a situation where we had a policy, which was to make the power plants capture-ready and also develop post-combustion capture that could be retrofitted to those plants, and that would have worked technically.
We then had the recession, a big reduction in demand, a big reduction in gas prices as a result, and all of those 10 coal plants were no longer going to happen. We had a demonstration programme that relied on retrofitting I think eventually it was four of those coal plants immediately with post-combustion capture, but there were no new coal plants to retrofit. Lord O’Neill mentioned that it is not worth retrofitting plants at the end of their life. Most of our coal plants are at the end of their life. We were proposing to retrofit Longannet. That plant really was too old to retrofit, I entirely agree. It was not retrofitted.
Unfortunately, that development could not go ahead. Neither of those developments were unreasonable in the circumstances. The Government—DECC—learnt from that. We now have the gas project at Peterhead, which is a sensible project that you could reproduce in large numbers either for new build or for retrofit. We have a new project on coal. It has to
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be a new project on coal to get the plant lifetime. We are now covering our bets quite well, and to say that it did not happen, there were very, very, very good reasons why things happened the way that they did.
Q97 Lord Dixon-Smith: It may not be considered a particularly helpful comment, but we are worrying frightfully about costs, and I entirely accept that in the short term—in a four, five, or possibly even a 10-year timescale—this is significant. But the significant aspect of it is the international competitiveness of our costs vis-à-vis everybody else’s costs. What the actual cost is and its movement over time does not matter. When I started in my farming business, I was paying between 1.25p and 1.3p for a litre of fuel oil, and we are where we are now and the world has not stopped. We are all affected by that in the same way. The issue of costs is relative.
Of course, where the Chinese, it seems to me, have their advantage at the moment is that they are using old technology in a completely uninhibited fashion, and they are not trying to improve it particularly. Mind you, if I had, as I suspect they still have, 100 million unemployed I would probably be inclined to do the same thing. But in the end, even they will have to come into the real world. The issue, in my book, is maintaining our relative position, because in this country’s situation in particular we are totally dependent for our living and our quality of life on our ability to export. If we cannot do that, frankly, we are bust.
The Chairman: Would anyone like to comment?
Dr MacLean: Yes. We need to be clear when we are talking about CCS and what has or has not happened since 2005. We are not talking here about a mature technology, we are talking about the need to demonstrate at a large scale. One of the learning points out of what has happened is that a competition at that early stage of development for a very, very big binary investment is not necessarily the best way to go. That is not alone a problem that the UK Government created. It is very much one that goes back to the question of state aids and the rules about how much money can be given to projects and in what way that can be given to projects.
I do think a more general question that we need to answer for ourselves is whether or not we are doing something for our own energy policy or whether we are doing something as an export. We must first of all be clear about that because the decision that Jon talked about not to do the Peterhead project—which I was involved in with SSE, who I worked with at the time—was that the Government made a decision that it was more of a priority to make CCS work on coal because that would be a technology that could be exported to China and India, rather than the right decision to be made for the UK’s own energy position, which would have been to do it on gas. Eventually, we have come around to that position.
The second part of it is if we are going to demonstrate these large-scale technologies and if we are going to develop them to commercial readiness and competitiveness, we have to make that investment upfront. We have to find a way of doing that that is much, much quicker and much more effective than the way we chose with CCS, which meant we lost the opportunity of the 2005 project with BP and had to reinvent it in a different form much, much later on. We are probably, what, six or seven years behind where we otherwise could have been. So, collaboration rather than competition, and asking are we doing this for
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energy policy, are we doing this for international policy on exports or economic policy, and making sure that we use the right tools for getting there.
Professor Gibbins: I think from a technical perspective the original Peterhead policy was too defensively engineered and the right technology is the one that we have now. As it happens, we are getting some benefit, significant benefit actually, from development overseas for that.
Dr MacLean: We could have still learnt about the transport and the storage elements of it rather than just the capture technology.
Professor Gibbins: We could have done, yes. Can I just say something in terms of what you were saying about what we are trying to do? What we are trying to do if we are spending money, I believe, is to avoid dangerous climate change. This is really important and we are not looking enough through that particular overall priority at what we are doing with our own energy industry. Clearly we do have to meet our legally binding targets, but that is, on its own, completely irrelevant for tackling climate change.
You can say we are trying to export technology, but what we are much more trying to do is to export ideas. The idea is basically that it is a good idea to capture CO2 when you are burning fossil fuel. People in China come to me when I go there to talk about CCS and say, “How many of these plants have you got working in the UK, Jon?” They smile because they know how many we have working in the UK, which at the moment is none.
You can look at it at a global level and say, okay, so the UK builds another major wind farm, onshore or offshore. Does anybody notice in the world? No. The UK builds another nuclear power plant. Does anybody notice? They may notice a little bit, but I do not think they will take a great deal of notice. The UK builds a couple of CCS projects, which is what we are talking about. Would they take notice? Well, that is a very, very significant part of global activity and, yes, they would take notice. In the big picture of trying to tackle climate change, influencing people with ideas is much more important than meeting our own targets. Everybody knows the UK is going to meet its CO2 targets if they are legally binding. We are a law-abiding country. We can do it. We have a lot of options. What we have to do is to persuade people, basically, that avoiding putting fossil carbon into the atmosphere when you use fossil fuels is cool. A number of countries overseas are quite happy to use a lot of our stylish objects, our consumer durables, our Rolls-Royce cars, you name it. Also, we need to get the idea that the UK thinks that not putting fossil carbon in the atmosphere is a cool idea.
Professor Nuttall: I should say that I am a believer in the energy policy triangle of three concerns of roughly equal weight that fluctuate in time, so I do not tend to put the environmental driver of climate change as somehow manifestly enormously more important than the other two. I would just point out, on the climate position, the need to distinguish, perhaps as was hinted earlier, between the track we are on and the track we all agree we should be on; they are not the same thing.
In terms of costs and affordability, I go with the European Nuclear Energy Forum on this, that we should start looking at whole system costs. We do not start with a proposition that something occurs privately in generation, and then after the fact of the decision, even before it is built, in a socialised space for transmission and distribution we all pay for it. Also, when we get to holistic thinking, that takes us to a new appreciation of holistic, whole
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system risks. When you are thinking about system resilience—and forgive me, Committee, it is not just about generation adequacy—I think we have to have a really fresh, 21st century look at whole system resilience, and that is where I hope your inquiry will go.
Q98 Lord Hennessy of Nympsfield: Can low-carbon technologies ever be cost effective? They have not been so far.
Dr MacLean: I think this goes back to the point that Lord O’Neill was making earlier on on the cost. What is the counterfactual? What is the comparison that we are making? Without putting a price on carbon and the impacts that that has, clearly, at the moment, the low-carbon technologies are not competitive with coal or gas or oil, otherwise they would be happening of their own volition. The issue is what price as a society we put on the avoidance of carbon. Then, within that, we can then say, “Do we reach this hurdle or not?” I would have to say, though, that if you look at some areas in the world, wind is already competing with unabated gas because it is in a very windy area and done very efficiently in the United States. If you look at some parts of the world, you have solar, which is already competing in very sunny areas where the productivity is high enough. What we need to recognise is that there is no fixed point in time with regard to cost.
Certainly, with regard to onshore wind and PV, we have seen with PV with every doubling of the volume a 25% cost reduction; with onshore wind with every doubling of volume a 15% cost reduction. Therefore, if we can get into the volume business we can see cost reductions that then bring us much closer to that point of parity, although the parity with what part still remains until we agree on what a robust carbon price is so that we know what that comparison overall is and can put it properly in the balance.
Lord Hennessy of Nympsfield: I was struck by your not mentioning nuclear, the Himalayan rise in cost, as Lord Rees put it.
Dr MacLean: Over the last decade, the cost of solar has gone down 80%, the cost of onshore wind has gone down 40%, the cost of fossil fuels, I think, has gone up by 40%, and the cost of nuclear has gone up by 100%. If you want some statistics, that is where they are at the moment. I was just making the point that there are low-carbon technologies where we have a proven track record of cost reduction and that that has been achieved in general through the increase in volume and the investment in innovation that has been put into that. Many Members were outlining that in the previous section with regard to solar and how the costs there have come down, but it should not be ignored that a lot of innovation has been very successful in bringing down the costs of onshore wind and, indeed, of the supporting infrastructures. Some of the grid developments are also bringing down the costs considerably, measured at a system level.
Professor Gibbins: Just with respect to costs, I am not sure you were phrasing it from this direction but an interesting question and a very important one is: will non-fossil energy sources become so cheap that fossil fuels are no longer attractive to use? What you have to recognise there is that fossil fuels are often sold at well above their production cost. If you start to get serious competition between non-fossil and fossil fuels, fossil fuel prices will reduce because they have to be sold still in some places. I agree there are situations where non-fossil sources can be attractive, but globally you will find that fossil fuels are likely to remain competitive in a sufficiently large number of places and enough quantity to cause serious climate risk.
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I certainly would not want to and I am obviously not personally relying on non-fossil energy becoming so cheap that it automatically displaces fossil fuels in time to avoid dangerous climate change. What you then have to do is to have carbon capture and storage as an option. Fossil fuels with carbon capture and storage will fairly naturally equilibrate with non-fossil sources because that will be your alternative. You will always go that way but essentially you will come down to the cost of low-carbon energy. You will be using different technologies in different places but costs will be roughly comparable for all the sources. Basically, there is probably—I do not know, pick a number—five times as much fossil fuel relatively readily available than we can safely put into the atmosphere, that sort of ratio.
Professor Nuttall: I would like to concur with what has just been said by the two other speakers and also note what was said by the speakers in the session earlier this morning. I thought that was very interesting.
On this issue of costs, it leads me to make a slightly philosophical point. Some years ago I co-authored a paper that stresses the need to distinguish between three timescales, one being the timescale of fossil fuel resource depletion, some number like 60 years; the timescale of climate change and our human responses to it, some timescale like 50 years; and then the timescale of technological innovation that we often forget is sometimes like 20 years, it is not overnight. This issue that the timescale of fossil fuel depletion and the timescale of the need to do something about climate change are similar numbers has in many people’s cases led to confused thinking. The reality could be that we face the need to decarbonise while fossil fuels remain abundant and affordable. We need to prepare ourselves for a world in which low carbon and, on the other hand, fossil fuel energy prices do not converge. That is a thought that has been said by several people this morning and that is a good framing for our thinking.
Turning to nuclear—because someone mentioned nuclear—there was some pessimism behind what I just said about cost convergence. Despite the fact that nuclear costs have, indeed, tended to rise, not fall, there are two possible points of optimism with regard to nuclear looking ahead. The first deals with today’s conventional technologies of large pressurised water reactors and the notion that still lies out there of improved economies of scale. The problem has been the term “the nuclear fleet” because, as it has been implemented, the fleet has always been too small and even the concept of the fleet has been problematic. Do we mean the national fleet of all the British nuclear power stations? Do we mean the global fleet of nuclear power stations operated by a given power company, or do we mean the global fleet of a given technology from a given vendor? Basically, these economies of scale have to be achieved without it becoming the local fleet of technology X operated by company Y in country Z. That is too small a community. Globalisation of nuclear power is a source of opportunity with given existing technologies.
The second idea, which is still to be proven, is that one might achieve economies not in unit scale but in volumes of production, and that takes us to the issue of small modular reactors, a topic that I know has been of much interest to Parliament recently so I will not say any more about it.
Q99 The Chairman: Perhaps you will say a word on this. One of the issues of nuclear is that it lacks flexibility, it is a base load. To what extent do you see the next generation of nuclear power stations being able to incorporate a greater degree of flexibility, thereby complementing these other sources of energy?
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Professor Nuttall: I note the evidence you received from the Nuclear Industry Association that future British nuclear power stations could be operated flexibly but it makes little economic sense to do so, and I would agree with that. Some years ago I co-authored a paper in the journal Nuclear Future concerning nuclear power flexibility and it goes into more detail than I will be able to today. I am happy to supply a copy of that to the Committee.
Looking, by the way, at the plants we already have in Britain, frankly, there is little prospect of operating the ageing advanced gas-cooled reactors flexibly. Although load-following, interestingly, could be technically possible, it is never going to happen from the AGRs, I would say. The interesting one that we have already is Sizewell B pressurised water reactor, which could be deployed for load-following and frequency response but there are no economic incentives to do that.
Looking longer term—and I think that was part of the spirit of your question—I would like to draw your attention to some very interesting ideas coming from Charles Forsberg and his colleagues in America. Charles is based at the Massachusetts Institute of Technology and they have a concept—and this is my impression of it—that they call the fluoride salt-cooled high-temperature reactor. It aims to maximise system flexibility and, therefore, increase revenues by 50% compared to a conventional base-load nuclear power station. Their FHR concept incorporates natural gas combustion with nuclear preheating, high-temperature thermal storage, electricity to stored heat conversion, and process heat services such as industrial or metropolitan steam supply. Interestingly, their focus has not been to reduce nuclear costs—the premise of your question—but rather to maximise revenues in liberalised markets with high proportions of intermittent renewables. I think that nuclear power innovation is going to be part of our future and there is some opportunity in terms of new technologies.
Lord O’Neill of Clackmannan: I am intrigued by what you are saying. You probably could also add that the small-scale nuclear reactors could be used for localised generation purposes in areas that were remote and that had only limited requirements, as they are doing, for example, in far eastern Russia where they have ships there. How economic they are I am not very sure. I just wanted to come in on the CCS question and I was intrigued because you started talking about nuclear. We have agreed then that probably the application of CCS in the UK will be limited given the fact that we are not going to have too many new gas-fired power stations and that we are really investing for an export market.
Professor Gibbins: No, I do not agree. I quoted to you results from the ETI that with a fairly significant deployment of CCS you would reduce the overall system costs for energy by tens of billions of pounds. I think that the prize of significant cost reduction will influence the mix and we will see significant carbon capture and storage.
Lord O’Neill of Clackmannan: Yes, okay, but in the UK, if we were talking about 1,800 megawatts per station, how many stations would you be talking about?
Professor Gibbins: Typical figures might be 10 gigawatts of generation by 2030.
Lord O’Neill of Clackmannan: That is seven or eight—
Professor Gibbins: Yes.
Lord O’Neill of Clackmannan: Seven stations across the country and all of them with CCS. But the point I am trying to get to is that if you were having that it would be alongside renewables and perhaps nuclear as well.
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Professor Gibbins: Yes.
Lord O’Neill of Clackmannan: You could get to a point where you say, in fact, we have not been that successful with the research and development. I just wanted to raise this simple question. We could be where we were in the early 1990s when we abandoned the fast breeder reactor because, in many respects, the fast breeder reactor arguments for it were very similar to those of CCS. Here was a technology that was going to solve a lot of the problems and we could export it on a big scale.
Professor Gibbins: I am not advocating that we can export it on a big scale. The UK has limited manufacturing capability in the power sector for exporting anything. We are not talking about particularly exporting nuclear power or even exporting wind; we are using it. It is there to help provide low-cost electricity for the UK, which is far more important than a small amount of export. It is important that we export the idea of using CCS and that is to get global climate change benefits, but the main benefits are at home. We can definitely realise those benefits, irrespective of whether or not we import technology, as we import a lot of generation technology, because it is based on our geology and our storage offshore. That means the fact that we have this storage available gives us a significant benefit in Europe. I take the point there, you do not have to be cheap, you just have to be cheaper than your competitors, and we can be. We have intrinsic advantages in the UK to use CCS, to decarbonise electricity. I can only quote you again the ETI results that CCS saved tens of billions a year. I can only put to you that if you want to maintain a certain amount of manufacturing industry in energy-intensive industry such as iron and steel or cement in the UK, you can decarbonise that using CCS so that the UK has a resource there that we can use and, if there are global CO2 targets, I believe we will use.
Clearly, if we have overbuilt a lot of intermittent renewables—the point that Dr MacLean made about you build things and then work out how to sort it out afterwards—I have to say I find, as an engineer, the suggestion that you would turn off a nuclear power plant rather than a wind turbine preposterous. I care deeply about climate, but why would you not just put the brake on a wind turbine rather than go to all the complication of modulating a nuke? You are not saving money, you are not saving CO2; you are just meeting some arbitrary target for renewables. This is cloud cuckoo land.
The Chairman: Professor Nuttall wants to come in.
Professor Nuttall: I would like to take the baton from Jon and move forward with it a little bit. What he is saying reminded me of a symposium that I attended at MIT in 2011 under the title, “Managing large-scale penetration of intermittent renewables”. One of the takeaway messages that I heard from the engineers there was that if one is to adjust the output of a fossil fuel power plant—so think an unabated coal-fired power plant—in order to admit the renewables that are always accepted by the system, what you are doing is you are taking your 1980s coal-fired power plant—we figured out how to work it—off the sweet spot. What happens is you lose your thermodynamic efficiencies, you lose your combustion efficiencies, and your CO2 emissions per kilowatt hour generated by the coal-fired power plant increase significantly. I am quoting my impression of their work but I found that quite interesting.
The Chairman: A last contribution from Lord Peston because we have run out of time.
Q100 Lord Peston: I want to put something to you on the cost-effectiveness question of Lord Hennessy because we are in great danger of getting the analysis wrong here. If, as
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would be expected, the typical British user of electricity bore the cost, then the cost they bore would be measured as a finite number. It may be a low finite number or a large finite number, but the benefit is infinitesimally small to the individual. Therefore, if you compare the cost/benefit every individual is going to vote against going for low-carbon technology. It is a well-known paradox in economics that the infinitesimal is of an order of magnitude—and is that not the danger of letting too many economists get involved in all of this, that it might be right to go for low-carbon technology even though primitive cost-benefit analysis would show that no individual gained, indeed they lose a finite amount? It is like it does not pay to vote because the probability of your changing the outcome of the election is infinitesimally small. As long as any cost is involved in your going to the station no one will ever vote, but then you end up with the paradox that the one person who goes to vote then decides the outcome of the election. We have to be very careful about how we work in—
The Chairman: A quick answer because we must finish.
Professor Gibbins: It is a classic commons problem. Everybody is better off if we avoid climate change and every individual is better off if somebody else takes the cost of avoiding climate change.
Dr MacLean: Can I just widen it out? We are talking about resilience here. You could argue exactly the same about security of supply and who is prepared to pay for security of supply. Ask a voter whether they want a higher bill just in case and the answer will be, “No, thank you”. It underlines how important it is that these decisions are taken in a rational manner rather than being left to a decision on the day by each and every one of us because we will get it wrong.
Baroness Sharp of Guildford: On top of that, probably the cheapest route to decarbonisation is energy efficiency and only if you raise the prices will the consumer think about cutting their use.
Professor Nuttall: I would urge the Committee—forgive the slight presumption in that—not to be afraid to focus on resilience and not feel the need to regard it as secondary to the climate change aspect. It is of huge public policy benefit that you are thinking about resilience, because not enough people have been, frankly.
As regards the global climate—ultimate tragedy of the commons—it is, frankly, for the United Kingdom in the domains of energy policy, research policy and what was once called industrial policy and it is not clear to me that we, the British, can do the most through our energy policy. Things we might sell and ideas we might export could do much more to help global CO2 emissions.
Q101 Lord Willis of Knaresborough: Professor Gibbins, could I ask you a technical question? In 2005 when I was in the Commons I chaired a report on CCS and it was quite exciting at the time.
Professor Gibbins: It still is.
Lord Willis of Knaresborough: It was an excellent report, thank you very much for endorsing that. One of the key things, though, in the questions was that the repositories in the North Sea were time limited. We are talking about nearly 10 years later. How long do we have before, in fact, that infrastructure just basically disappears?
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Professor Gibbins: Yes. Clearly, the actual sites themselves are there forever. What we were talking about doing, I believe, in 2005 was using the carbon dioxide to get more oil out from existing oilfields. Some of the fields have been closed and the Miller field that was going to be used at Peterhead is closed, but there are still a number of fields left. We still have that window. The Scottish Government, I have to say, has taken using CO2 for enhanced oil recovery very seriously because, particularly for the Scottish economy, it would have a major impact. Going forward, particularly if we get the Peterhead project going and there is CO2 available further north, we will see some developments on CO2 EOR. Yes, we have lost some fields but there are others becoming available. I do not think that particular play is over yet.
The Chairman: Again, I refer back to the written evidence from the Carbon Capture and Storage Association. Maybe they are probably biased, but they assured us that there was more than enough storage of geological formations for the next 100 years.
Professor Gibbins: Yes. This was just specifically for injecting CO2 into existing oilfields before the platform is closed.
The Chairman: That concludes this morning. Again, as before, we would have liked to have continued rather longer, I suspect, but you have given us a lot of interesting thoughts to follow up. I know, Professor Nuttall, you have said that you would send us some further information, for which we are grateful. Indeed, if the others would like to follow up with anything that you feel you have not had an adequate opportunity to cover, please do so. We would be very happy to receive anything further. You have given us some particularly helpful thoughts about cost convergence or the lack of it and, indeed, the ultimate reason why we need to pursue resilience as well as a wider portfolio. Thank you for a very stimulating discussion. I am most grateful.
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Government – Written evidence (REI0040) This memorandum has been prepared by: Department for Energy and Climate Change (DECC) Introduction The Department of Energy & Climate Change (DECC) works to make sure the UK has secure, clean, affordable energy supplies and to promote international action to mitigate climate change. The following evidence is submitted on behalf of DECC in response to the House of Lords Select Committee Call for Evidence, launched on 24 July 2014. Summary Energy security is about making sure consumers can access the energy they need at prices that are not excessively volatile. The UK has experienced strong energy security from a combination of its liberal energy markets, firm regulation and extensive North Sea resources. The outlook for UK energy security remains strong, but we remain vigilant. While the UK’s energy system is relatively resilient to energy security challenges, it faces ongoing risks from severe weather, terrorist attacks, technical failure and industrial action. These risks can be mitigated but it is impossible to avoid entirely. In the medium to long term the UK’s energy system also faces a great deal of change as existing infrastructure closes, domestic fossil fuel reserves decline and the system adapts to new technology, including a more decentralised and intermittent supply as an inevitable consequence of a higher mix of renewables. These changes will create new challenges for UK energy security in the years ahead. As the Department with responsibility for ensuring secure energy supplies, DECC has a strategy in place to make sure the UK’s energy system has adequate capacity and is diverse and reliable. Over the short term, action is being taken to keep capacity online and manage demand. In the medium term, Contracts for Difference and the Capacity Market are set to unlock further investment. Over the long term, the whole EMR program, new nuclear and new technology will create a stable system for low carbon, affordable and secure energy. DECC is also very active in partnering with other parts of government, industry and academia to address the engineering and innovation challenges. The UK has some world-leading expertise, including in low carbon transition. Our written evidence addresses the questions raised by the Committee, and gives a detailed summary of our understanding of each question and the work we are undertaking that is relevant to these. 1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden
shocks? How well developed is the underpinning evidence base?
1.1 Ofgem’s Electricity Capacity Assessment Report 2014 assesses the risks to electricity security of supply in Great Britain for the next five winters. The assessment is based on data from National Grid accompanied by internal analysis. Measures used to assess
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security of supply include de-rated margins, loss of load expectations and the risk of customer disconnections.
1.2 The report suggests that that the risks to the security of the electricity supply over the
next five winters would be broadly consistent with those in the 2013 report. However, the risk to customer disconnections has reduced due to new measures introduced by the Government, Ofgem and National Grid.59 De-rated margins are expected to reduce over the next two winters, dropping to their lowest level in 2015/16, driven by a reduction of electricity supplies from conventional generation. De-rated margins are then expected to improve as new measures (such as the Capacity Market) are introduced, new conventional plant comes online and some mothballed plant returns to the market.
1.3 National Grid Electricity Transmission plc (NGET) is the National Electricity
Transmission System Operator (NETSO) for Great Britain. NGET also own the electricity transmission networks in England and Wales. In addition to NGET, the electricity networks in Scotland are owned by Scottish Power Transmission Limited (SPTL) in south and central Scotland and Scottish Hydro Electric Transmission plc (SHE Transmission) in the north of Scotland. The National Electricity Transmission System Performance Report 2012-13 includes statistics for SPTL and SHE Transmission.
1.4 In accordance with Standard Licence Condition C17 (Transmission System Security, Standard and Quality of Service) of its Transmission Licence, NGET, as NETSO, is required by the Gas and Electricity Markets Authority, to report National Electricity Transmission System performance in terms of availability, system security and the quality of service. National Grid therefore publishes annual - National Electricity Transmission System Performance Reports and Summer and Winter Outlook Reports for electricity and gas. National Grid has published the Winter Outlook Report for over a decade and the Summer Outlook report since 2008, allowing them to build a robust evidence base to demonstrate the resilience of the system and reliability of modelling. The outlook reports have evolved over the years taking into account stakeholder feedback. The Winter Outlook Report 2014/15 is currently published for consultation. The 2014/15 report compares the forecast with the actual weather for the 2013/14 period and shows that, despite low demand levels, demand side response was far higher than in previous years. The report also compares actual with forecast generator availability and states the lowest generation margin for winter 2013/14 was 7%, however this was still seen as an adequate margin and no system warnings were issued.
1.5 Looking forward to this winter, the outlook report proposes to harmonise the security of supply analyses with the Ofgem Electricity Capacity Assessment Report, discussed above, to establish a reliability standard for security of supply, as introduced by DECC in the Electricity Market Reform Delivery Plan.
59 Earlier this year National Grid announced two new services that it intends to procure to use for the purpose of balancing the system and which will provide additional capacity over the next two winters beginning with winter 2014/15 (with the potential of extension for a further two years if necessary, subject to Ofgem approval) in order to mitigate the risk of low capacity margins.
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1.5 The most recently published National Electricity Transmission System Performance Report is for 2012/13. The performance report discusses both availability and security of the transmission network, which provides an indication of the resilience of the UK’s electricity system.
Availability 1.6 System availability is reduced whenever a circuit is taken out of operation for either
planned purposes or as a result of a fault. National Grid monitors the National Electricity Transmission System performance by reporting variations in Annual System Availability, Winter Peak System Availability and Monthly System Availability. The Annual System Availability of the National Electricity Transmission System for 2012-2013 was 94.75%. Figure 1 shows how this compares with previous years.
Figure 1: % Annual System Availability Taken from the National Grid National Electricity Transmission System Performance Report 2012-2013 http://www2.nationalgrid.com/UK/Industry-information/Electricity-transmission-operational-data/Report-
explorer/Performance-Reports/
1.7 In 2012-13 the annual system availability for SPTL was 95.72%, slightly higher than the previous two years. The SHE Transmission annual system availability was 96.48%.
Security 1.8 System performance is monitored by the Estimated Unsupplied Energy from the NGET
Transmission System for each incident. During 2012-13 there were 351 NGET system events where transmission circuits were disconnected either automatically or by urgent manual switching. The vast majority of these events had no impact on electricity users with only 3 resulting in loss of supplies to customers.
1.9 Figure 2 shows the annual comparison of the numbers of Loss of Supply Incidents that
occurred within the NGET Transmission System, showing that 2012-2013 had significantly less incidents that the four preceding years.
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Figure 2: Number of Loss of Supply Incidents Taken from the National Grid National Electricity Transmission System Performance Report 2012-2013
1.10 The Overall Reliability of Supply for the NGET Transmission System during 2012-13 was 99.99999%. This compares with 99.99972% in 2011-12 and 99.99998% in 2010-11.
1.11 The Overall Reliability of Supply for the SPTL Transmission system during 2012-13 was
99.99968% compared with 99.99975% in 2011-12 and 99.99600% in 2010-11. 1.12 The Overall Reliability of Supply for the SHE Transmission system during 2012-13 was
99.99123%, compared with 99.99228% in 2011-12 and 99.99956% in 2010-11. 2 What measures are being taken to improve the resilience of the UK’s electricity
system until 2020? Will this be sufficient to ‘keep the lights on’?
Investment 2.1 The network companies are investing in replacement assets and ensuring that new
generation is accommodated in a secure manner. For transmission £6 billion has been ear marked for the 2013-21 price control period, to replace ageing assets mainly built in the 1950s and 1960s. Distribution networks are currently in the process of having their business plans approved through the price control process RIIO ED160 which will help to determine the amount of money they invest in their networks. This will involve replacing ageing assets and strengthening their asset base where they expect increasing loads. This will be done by increasing capacity at sub-stations, further flood protection and improved network configuration.
2.2 Network companies are also carrying out a wide range of innovative projects through
Ofgem’s £500 million Low Carbon Networks Fund and other innovation funding sources. These projects have enabled them to test new technologies and ways of operating the network through increased monitoring and control, which enable the network operators to identify and fix faults more quickly. Smart technologies and new commercial practices will enable network operators to integrate new tools, such as storage and demand side response, to help balance supply and demand.
60 RIIO-ED1 is the first electricity distribution price control to reflect the new RIIO (Revenue = Incentives + Innovation + Outputs) model for network regulation. Source: https://www.ofgem.gov.uk/network-regulation-%E2%80%93-riio-model/riio-ed1-price-control
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2.3 The introduction of the Capacity Market, as described in paragraphs 1.2 and question 4, will also help improve the resilience of the system.
Reducing risk 2.4 The cross sector National Risk Assessment (NRA) is updated bi-annually (from 2014,
previously annually) and provides a SECRET, strategic assessment of the most significant emergencies that could affect the UK over the next 5 years. A declassified version, the National Risk Register is published by the Cabinet Office.61 These assessments underpin energy sector resilience planning and are used to inform the energy sector resilience plan, which provides assurance to ministers that mitigations and programmes are in place, and reports on the progress of delivery.
2.5 As of May 2014 DECC owns 15 risks within the NRA 2013. Currently, the top ‘hazard’
risks to electricity networks include: pandemic flu (for impact on staffing), coastal flooding, major industrial accidents and weather related risks (low temperatures & heavy snow, heat waves and storms & gales as well as severe space weather). Top ‘malicious’ risks include cyber-attack and ‘conventional’ attacks on infrastructure.
2.6 To reduce the likelihood of these risk events occurring, DECC works in partnership with
industry, regulators, consumers and wider government stakeholders to ensure the resilience of the energy network, and in the event of a disruptive event, there is an effective and efficient response. Officials from Energy Resilience in DECC attend regular industry task groups, including Electricity, Gas, Communications and Security, to drive forward commitments and specific work packages to improve resilience and reduce the impact of known risks.
2.7 DECC also oversees programmes and initiatives to improve and manage the security of
key energy sites, enhance flood protection at sites most at risk, and supports the implementation of vegetation management to reduce the risk to electricity supplies from storms and gales.
2.8 Following the power disruptions, as a result of severe weather, which affected 750,000
households over Christmas 2013/14, the Secretary of State met Chief Executives of the electricity Distribution Network Operators in January62 to identify lessons to be learned. Subsequently DECC published a Review in March63 on the performance of the network operators. Despite the strong response - 95.3% of disrupted customers were restored within 24 hours - the Review highlights areas for improvement to ensure that in future customers experience as little inconvenience as possible. The Review established 24 actions for industry and 2 actions for DECC to take forward. These actions cover: Communications with customers, Resource management, Engagement with the media, Welfare provision and Goodwill payments.
61 https://www.gov.uk/government/publications/national-risk-register-for-civil-emergencies-2013-edition 62 https://www.gov.uk/government/news/customer-communications-at-heart-of-review-into-dealing-with-widespread-power-cuts 63 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/287012/DECC_-_Festive_disruption_review_-_Final__2_.pdf
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2.9 All of the actions are being progressed currently, with the aim of completion, with the
exception of the single national number, in September 2014. As part of the actions, the Energy Networks Association is progressing the establishment of a Single Emergency Number for customers to use to contact their Network Operator in the event of a power disruption64. The implementation of this number is currently expected in spring 2016. DECC continues to closely monitor the progression of this work, and is represented on both the Programme board, as well as the task groups working on the detail of the solution.
2.10 In addition to this on-going work, cyber security is also playing an increasingly
prominent role in the Department’s work and we are working with other government departments and agencies, as well as with industry partners, to ensure that the risks to the energy sector are understood and that appropriate mitigations are established.
3 How are the costs and benefits of investing in electricity resilience assessed and how
are decisions made?
3.1 For networks, the Distribution Network Operators must identify and justify measures to improve the networks to Ofgem. These measures should ensure network resilience while delivering value for money for consumers. As part of the RIIO price control process, the network operators are using an asset health measure which rates assets on their age and condition and maps across to their criticality i.e. the impact of an asset fault on performance, safety, environment and cost. This risk and impact assessment helps the network companies to prioritise and allocate expenditure appropriately.
4 What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
Electricity Market Reform 4.1 The Electricity Market Reform (EMR) programme, which went live on 1 August 2014, is
promoting investment in secure and low carbon electricity generation, while improving affordability for consumers. The Government is reforming the electricity market in response to the challenges facing the electricity sector:
The UK faces closure of existing capacity as older, more polluting plant go offline.
Our generation mix needs to respond to the challenge of climate change and meet our legally-binding carbon and renewable targets.
Electricity demand is expected to continue to grow over the coming decades as we increasingly turn to electricity for heat and transport.
64 http://www.energynetworks.org/info/emergencies/single-emergency-number.html
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4.2 This amounts to a significant investment challenge, with an estimated £100 billion of further investment needed in the sector through to 2020. This investment has the potential to support up to 250,000 jobs in low carbon electricity over the same period.
4.3 Securing this investment will help to deliver on the Government’s objectives for the
electricity market:
maintaining security of supply, ensuring that the lights will stay on;
making progress towards our decarbonisation and renewables targets; and
ensuring that consumers pay a fair price for low carbon electricity.
4.4 Electricity Market Reform puts in place two key mechanisms to provide the necessary incentives for the investment required in our energy infrastructure to meet these objectives:
Contracts for Difference (CFDs) provide long-term price stabilisation to low carbon plant, allowing investment to come forward at a lower cost of capital and therefore at a lower cost to consumers;
The Capacity Market provides a regular retainer payment to reliable forms of capacity (both demand and supply side), in return for such capacity being available when the system is tight.
4.5 DECC considers that the legislative framework and these instruments create a clear regulatory framework which will help stakeholders finance their projects at lower cost. This in turn will help bring forward the new renewable energy infrastructure the UK needs to maintain security of supply and meet its climate change objectives, all the while keeping costs for consumers as low as possible.
4.6 In developing the reforms DECC has sought to provide the right balance of certainty in
the regime – by setting the framework in the implementing regulations and some of the more technical detail in documents such as the Capacity Market Rules and the Allocation Framework. Some of the CFD budget was released early to successful projects in the Final Investment Decision (FID) Enabling for Renewables process in order to avoid an investment hiatus ahead of the full implementation of the enduring regime. In this way, stakeholders have certainty about how particular policies will work whilst the flexibility is retained to make changes quickly to ensure the integrity of the policies is maintained and our objectives met.
4.7 This also ensures that the arrangements will work on a practical level for industry - it is
a complex area and we need to ensure the regime can evolve and adapt where needed if it is to meet its objectives.
4.8 The reforms are already starting to deliver investment. Under the FID Enabling for
Renewables process, eight renewable electricity projects have signed Investment Contracts (an early form of CFDs), based on information provided by projects, they are expected to bring forward up to £12 billion of private investment.
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4.9 These projects include biomass conversion, dedicated biomass with combined heat and power and offshore wind. This will bring forward:
up to 15 terawatt hours per year of generation capacity – enough to power the equivalent of up to three million homes;
over 4.5 GW of generation capacity;
support up to 8,500 jobs [Figures are estimates based on information from industry and compiled by DECC];
contribute a 10 megatonne CO2 reduction in the UK power sector emissions per annum compared to fossil fuel generation;
contribute around 14% of the renewable electricity required to meet the UK’s 2020 renewable energy target.
4.10 The Capacity Market will also drive new investment – in generation and demand side response – as well as ensuring that we get the best out of our existing assets. The first capacity auction will take place in December 2014, with successful bidders committing to be in place for the winter of 2018. We expect a competitive process with bids from new and existing capacity and from a range of technologies and providers. This will ensure that we secure the volume of capacity we need to ensure future security of supply at the best price for consumers.
4.11 Government is committed to support for renewable electricity generation, and to a
diverse technology mix. The Government’s Levy Control Framework controls the total amount of support available for low carbon generation, helping to ensure costs are affordable. There is sufficient budget available to meet the Government’s 2020 renewable targets and longer term decarbonisation goals.
Maintaining network resilience 4.12 Networks have an important role to play in helping to ensure that DECC’s
decarbonisation goals are met. As part of its System Operator role for the GB network, National Grid publishes an annual Electricity Ten Year Statement65. The statement sets out a number of scenarios to 2030 and what network investment might be needed to ensure that new generation and demand can be accommodated and system security and resilience maintained. The scenarios and potential solutions are subject to extensive stakeholder engagement. The Statement also includes a detailed appendix on technology which assesses the current and future network technologies for developing both the onshore and offshore transmission system.
4.13 Distribution Network Operators (DNOs) have developed the model “Transform”
through the Smart Grid Forum this feeds in the Governments trajectories for take-up of low carbon technologies, this helps them to assess what future investment is needed in their networks. The DNOs are actively planning for the take-up of low carbon technologies including electric vehicles, heat pumps and PV; the smart grid will play a key role in helping them meet these challenges.
65 http://www.nationalgrid.com/uk/electricity/ten-year-statement/.
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Price control mechanisms 4.14 As the regulator of the electricity market, Ofgem is responsible for scrutinising network
costs and ensure, through its extensive price control process, that network operator expenditure is fully justified.
4.15 Ofgem has demonstrated it is prepared to challenges network companies on their
costs. For example, as part of the RIIO-T1 price control Ofgem reduced National Grid’s original funding request by £1.7 billion (or 10%) to deliver the same outputs. Similarly in relation to electricity distribution price control, RIIO-ED1, a £2.1 billion reduction from initial DNO business plans in total expenditure has been proposed in Ofgem’s draft determination. Over £800 million reduction in potential costs has been identified through smart solutions which defer the need for network reinforcement and the need for engineers to attend speculative faults on the networks. In addition to this, there are incentives within the price control process that encourage network companies to find further savings.
Energy Sector Resilience Plan 4.16 The Energy Sector Resilience Plan (SRP) is an on-going assessment of the resilience of
the energy sector to the risks set out in the National Risk Assessment (NRA), as well as other significant risks the Department works with industry to manage. The risks to the sector are taken from the NRA. Electricity sector specific risks, such as technical failure of the national grid transmission system, as well as cross-cutting risks that, if realised, would have an impact on the electricity sector, such as pandemic flu and severe winter weather are both considered. This approach acknowledges the interdependencies across sectors, and the potential impacts on supply chains which can cause further disruption within a sector.
4.17 Risks are assessed by DECC as to how they impact the sector, to provide a holistic
overview of the sector’s ability to anticipate absorb, adapt to and recover from disruption resulting from the risk. Exercises, such as the recent Tier 1, cross-government Exercise Hopkinson, are developed based, in part, on the SRP and seek to strengthen resilience, capability and response. Hopkinson focused on the event of a widespread electricity transmission system technical failure.
4.18 The Energy SRP is reviewed annually by DECC, working with industry, to ensure that
the assessment remains accurate. The assessment process will be maintained to identify any emerging risks and enable DECC to take action to manage and / or mitigate the occurrence of these risks.
5. Will the next six years provide any insights which will help inform future decisions on
investment in electricity infrastructure? Electricity Market Reform
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5.1 The Government is committed to monitoring and evaluating the Electricity Market Reform (EMR) programme as it is implemented to ensure its benefits are being realised and so that any lessons learned from the initial stages of the programme can be brought to bear on subsequent stages. The Government is also committed to reviewing the operation of the programme at appropriate points in the future to ensure it is continuing to cost-effectively support the UK’s energy objectives.
5.2 DECC currently envisages that the evaluation of EMR will include (but not be confined
to):
an assessment of the extent to which the first round of awards of Contracts for Difference (CfD) under the enduring regime have furthered the UK’s low-carbon energy objectives at least cost to consumers;
an evaluation of the extent to which the first Capacity Market auction has met expectations of providing security of supply; and
an assessment of whether the institutional framework underlying the programme is fit for purpose.
5.3 The timing of these reviews and their outputs are still being considered. Transitional Arrangements for Demand Side Response in the Capacity Market 5.4 DECC has developed Transitional Arrangements to help new Demand Side Response
(DSR) providers that are not yet mature enough to compete against generation in the main Capacity Market and in so doing help grow the sector. Developing the DSR sector into a broader and more flexible reserve resource will better support the expansion of renewable generation, removing the need for more peaking plants and helping to cut carbon emissions.
5.5 During winter 2013/14 Triad period, typical DSR levels experienced were 1.2GW and
on occasion up to almost 2.0GW66. We hope to grow levels of DSR through the Capacity Market. Evidence from US shows that in 2012 DSR delivered 6% of peak capacity across the US and the PJM Capacity Market alone has brought forward about 15GW of DSR over 10 years.
Electricity Demand Reduction 5.6 DECC launched the Electricity Demand Reduction (EDR) pilot on 29 July 2014 which
aims to examine the viability of EDR in the Capacity Market and to learn lessons for government and stakeholders on the delivery of EDR schemes. The pilot will be backed with at least £20million of funding for the installation of more efficient electrical equipment (which provides lasting rather than temporary reductions). Measures could include efficient motors, air conditioning and lighting.
66 National Grid’s 2014 Winter Consultation Report.
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5.7 EDR projects could potentially participate in the Capacity Market as they reduce the demand placed on the system and in turn lower the amount of generation capacity that needs to be delivered to meet that demand. A decision as to whether EDR will participate in the Capacity Market will be made following a review of the pilot.
Low carbon technologies 5.8 The next 6 years will give a further insight into the future take-up of low carbon
technologies and the likely impact this will have on networks infrastructure. There will also be further findings from the projects taking place under Ofgem’s Low Carbon Networks Fund and the Network Innovation competition. This can help identify the technologies that can be used to help keep costs down by providing solutions to increased network capacity without always needing to reinforce.
6. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will
new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
6.1 Over the medium term, there will be an increasing dependency on the continuous availability of an electricity supply, for example through increasing electrification of heat and transport. Designing and operating the national electricity network will become more complex with an increasing volume of renewable supply sources (which are diffused around the network and of variable availability). Robust control systems will be required to balance the resulting increasing complexities, together with sufficient transmission/ distribution network capacity and possibly an increasing need for interconnections with international systems for access to a wider pool of renewables and reserves. New technologies and services, such as Demand Side Response and storage services, may come to play an important role.
6.2 Interdependencies with other energy delivery systems (such as the gas network) will
increase. Together these factors will result in a national electricity system reliant on advanced means of managing a multitude of options on both the supply side and demand side. It is possible that the network of the type described here would rely heavily on a vastly increased volume of control data, increasing the importance of cyber security.
6.3 In this rapidly evolving environment there is always the potential for new risks to
emerge, and over a medium term timescale it is likely that this will happen. The robust procedures in place for the National Risk Assessment and the Energy Sector Resilience Plan, as described in the response to Q4, ensure there is a regular process to challenge current knowledge to identify potential new risks, and that, where a new risk is identified, robust assessment occurs, against which mitigation strategies can be developed.
7. What does modelling tell us about how to achieve resilient, affordable and low
carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models?
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7.1 Modelling tells us that for a resilient and lower carbon infrastructure we need a balance of a number of generation technologies, along with demand control capability. In an electricity system which has a large volume of new technologies connected (such as solar photovoltaics, different configurations of wind generator, etc.) other technologies need to provide the balance of supply and demand, and also related system services (e.g. provision of back up reserves, and other technical services).
7.2 DECC’s central modelling tool used for Electricity Market Reform (EMR) evidence is the
Dynamic Despatch Model, which models the generation mix and capacity margins. For robust modelling of power system resilience, a number of other aspects also need modelling, aside from the basic supply/demand balance. These include understanding the dynamic control of the electricity system, and how different types of generation plant (and other technologies) interact. National Grid is conducting their own modelling work in this area, and a number of academics are working with them and others in the field on the underlying engineering questions. DECC, in collaboration with GO-Science, have asked the council for Science and Technology to commission a study of electricity system modelling capability in the UK market, to understand whether there are any significant gaps in capability which government or industry need to address. This study is being led by the Institution of Engineering and Technology. DECC’s Science and Innovation team is working on developing new whole systems methods in collaboration with the InnovateUK Energy Catapult and is also undertaking in-house modelling on how the electricity system could be balanced in future. This type of modelling is highly technical and relies on data and evidence provided by a number of industry organisations, primarily by the system operator, National Grid.
7.3 The modelling undertaken by the Smart Grid Forum has identified that smart
technologies and commercial solutions combined with conventional solutions can help achieve significant savings on network reinforcement. This is on the basis that smarter control of the electricity system assets can result in them being used more efficiently, and therefore mitigate large capital sums which would otherwise have to be spent on network reinforcement to deal with new generation and demand technologies (e.g. electric vehicles, or large distributed populations of solar photovoltaics). DECC also intends to expand its own modelling capability to estimate costs associated with a resilient future low carbon system.
7.4 The current models used by the electricity industry are adequate to provide evidence
in the short term. In the medium term, modelling approaches need to evolve to take in whole systems issues, in order to ensure lowest cost energy infrastructure development. The need for new approaches is driven partly by the addition of distributed, and variable renewable generation, and partly by the changing properties of demand (for example, modern lighting technologies have different electrical characteristics and on aggregate they change the way the electricity system as a whole behaves). In conjunction with the above, the advance of widespread communications connectivity and big data analytics open up new approaches to the control system of both generation and demand.
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7.5 Whilst modelling of these issues applied to the electricity system is the subject of significant attention, it is also important to consider interactions between different parts of the energy system as a whole, e.g. between the electricity and gas grids, and between home automation and the electricity system. The Energy Research Partnership, of which DECC is a co-chair, is conducting work into this area to identify who is doing what in the wider landscape, and whether there are other areas to address. The Energy Technologies Institute is also doing useful research in this cross-disciplinary area and DECC is closely involved in their work activities.
7.6 Conventional solutions to manage the power system in the medium term may demand
new technological solutions, operational practices and commercial arrangements, all dependent on technical progress of relevant technologies. DECC intends to work with the new Energy Systems Catapult to build the base of research and data which government and industry may need in this area.
7.7 An important underpinning issue in all of the above activities is the sharing of data so
that researchers and the R&D community can use realistic data to develop more accurate modelling, for example of different types of consumers’ demand at a more granular level than is available currently. This is an issue DECC continues to explore with the industry through fora such as the Smart Grid Forum and Energy Networks Association.
8. What steps need to be taken to ensure that the UK’s electricity system is resilient as
well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
8.1 With the projected increase in electrification of transport and heating and increasing distributed generation Distribution Network Operators (DNOs) may need to adapt and become more like DSOs where they can act as local system operators increasingly balancing demand within their local network.
8.2 Our long term vision for the electricity market is for a decreasing role for Government
over time and for a market where low-carbon technologies can compete fairly on price. Electricity Market Reform (EMR) provides the process and mechanisms to enable us to make this transition. However, given that many low carbon technologies are at a different stage of development, this long term vision remains at least 10-15 years away.
8.3 The support provided by EMR is vital if we are to ensure the country has a diverse
electricity generation mix and to ensure we have a portfolio of low carbon technologies rather than becoming overly reliant on any particular one. The carbon price is also currently too low to encourage investment in low-carbon generation on its own.
8.4 For example, for Contracts for Difference, our ultimate aim is that all technologies
should move to competitive allocation as soon as it is appropriate to do so, with the eventual aim of technology neutral auctions for all low carbon generation.
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9. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
9.1 With increasing levels of variable, renewable generation on the electricity system, new technology solutions need further development to ensure efficient investment overall, and optimise whole system costs, while assuring a resilient system, with adequate security of supply. Two technologies are fundamental; electricity storage and demand side response (DSR). In addition smarter grid infrastructure (involving more sophisticated use of control systems and power electronics) could play an increasing role. Of these, breakthroughs in energy storage technologies which might offer a step change in their whole life costs would be highly disruptive and open new possibilities for the generation technologies mix for a low carbon system.
Electricity Storage 9.2 Energy storage systems – which can store surplus electrical energy for use at times of
high demand – can help to support the wider deployment of low carbon, but variable, generation and can contribute to the resilience of the electricity infrastructure. DECC’s report ‘Electricity System: Assessment of Future Challenges’, published in August 2012, concluded that “increasingly, balancing technologies (electricity storage, demand side response and interconnection) and smarter networks will be required to help match the supply and demand of electricity efficiently and cost-effectively”.
9.3 Different balancing mechanisms are expected to be needed to meet different
balancing needs in the transmission and distribution networks, depending on the characteristics they offer, such as their peak power; duration of storage; and response times. The extent of deployment and effect of storage on energy costs will depend on the composition of future electricity systems as well as the cost and availability of storage and the other balancing technologies.
9.4 Different energy storage technologies are currently at different stages of development
– and further innovation and development are needed to make energy storage cost-effective for wide deployment.
9.5 The Low Carbon Innovation Coordination Group (LCICG), which includes DECC and the
other major public-sector backed organisations that invest in low carbon technology innovation, published a Strategic Framework in February 2014, which prioritises future innovation needs in 11 key technology areas – including electricity storage. While the Strategic Framework highlights the uncertainty about the exact role for storage in the future energy system and the role of different storage technologies, it has identified strategic priorities for continued and future UK innovation investment in electricity storage. The LCICG’s 2012 Technology Innovation Needs Assessment (TINA) for Electricity Networks & Storage also concluded that “while some of this innovation potential could be realised through ‘learning-by-doing’ we [LCICG] expect that over half the cost reduction potential to 2050 would be driven by RD&D”. For storage
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technology specifically, the TINA indicates that innovation in energy storage technologies has the potential to yield estimated total system cost savings of £5 billion (range: £2-10 billion) up to 2050.
Demand Side Response 9.6 Resilience of the supply in a network with a high degree of renewable generation
depends on matching the demand for electricity with the availability of variable generation. Demand Side Response (DSR) schemes can be used better match demand with supply, for cost effective renewable generation integration to UK networks.
9.7 DSR in the UK electricity network is not new, and has been used in the UK Electricity
Network for at least the last 60 years to balance available generation with demand. However, in the past, providing DSR has been more suited to large industrial consumers of electricity, e.g. such as in smelting of aluminium, where the manufacturer offers to suspend production at times of network stress in return for lower electricity prices.
9.8 Traditionally providing DSR has required manual systems to curb electricity demand in
response to a signal provided by National Grid. New technology based on Information and Communication Technology (ICT) is now in the market that enables DSR to be automated, with an electronic signal being sent by the system operator via companies that act as ‘aggregators’ of DSR. This technology is cheaper and much more applicable to a variety of commercial activity in the service sector as well as in the industrial sector. Examples include aggregators delivering DSR through office blocks that instruct their building management systems to turn down their air conditioning temporary in response to a signal. The high thermal storage provided by the concrete in these buildings means that occupants do not notice for short periods. The aggregators get paid by the system operator and in turn pay the office block for providing the service.
9.9 As the amount of variable renewable energy generation in the network increases
beyond 2020, the amount of DSR required to balance the network is expected to increase; given the current costs and state of electricity storage. In addition, the increased use of distributed generation, charging of electric vehicles and the use low carbon heat technologies such as heat pumps may require localised DSR to be provided to avoid expensive strengthening of the low voltage (LV) distribution network.
9.10 In future, the Government expects that the trend towards ICT enabled automated DSR
will lower costs and allow consumers of low amounts of electricity to participate in providing increasingly higher amount of DSR. In particular, the roll-out of 53 million smart electricity and gas meters in homes and small businesses across Great Britain by the end of 2020 will provide a mechanism for individual domestic and small business consumers to participate in providing DSR.
9.11 The smart metering technology which facilitates DSR will form part of the ‘Smart Grid’,
whereby an interconnected network of smart meters, smart heating controllers and
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smart appliances that will enable the benefits of time-of-use (ToU) tariffs and DSR to be rolled out to all electricity consumers using a high degree of automated control. This will include monitoring of the electricity LV network to identify pinch points and enable better use of local generation in the network.
Power Electronics and Control Systems 9.12 Many so-called ‘smart grid’ technologies exist today but their cost and complexity
mean that they are only used for niche applications, for example in situations where very high value is placed on avoiding supply interruptions, or in isolated grids (e.g. Scottish Islands) where the use of new technologies can defer or remove the need to spend large sums of money on conventional technical solutions. Other potential advantages can include speeding up and lower in the cost of new connections.
9.13 The technologies are already being rolled out through smart grid demonstration
programmes which have been taking place over the last few years; the aim is to identify which of these technologies provide the best value for money. Ofgem funding has been particularly valuable in incentivising utilities to trial and demonstrates these techniques and systems, and experiment with other stakeholders in how to use them. Major technologies being used in these programmes include Active Network Management, Storage, voltage optimisation and also novel commercial solutions, e.g. aggregating demand through new DSR providers.
10. Is UK industry in a position to lead in any, or all, technology areas, driving economic
growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
10.1 The UK network companies have had a unique opportunity to trial new technologies by the Regulator making funding available through the Low Carbon Network Fund and its successor scheme, the Network Innovation Competition, to carry out Smart Grid Demonstration projects (other EU countries are now looking at how best to replicate this). There is also funding available for innovation through the EU 2020 Horizon project and other schemes through the Energy Technologies Institute and the Innovate UK. The EU’s Joint Research Council report67 (page 32) shows the UK as having the second largest budget in Smart Grid demonstration and Research and Development, just behind France.
10.2 We expect to see innovation in products and services that will use the smart
metering system to help consumers manage their energy use and bills. For example, British companies, including product designers and manufacturers, are already developing products which can connect to smart meters and stream consumption data via the internet.
10.3 It is not clear whether any one ‘smart’ technology approach or technology family is a
clear winner in the UK context. There are, for example, a number of possible technical
3 http://ses.jrc.ec.europa.eu/sites/ses.jrc.ec.europa.eu/files/publications/ld-na-26609-en-n_smart_grid_projects_outlook_2014_-_online.pdf
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approaches to energy storage with overlaps in terms of their potential addressable applications. The UK is a relatively small percentage of the world market for many of the technologies of interest. The likelihood is, therefore, that for given technology families, costs reduction curves will be driven by their global uptake and consequent economies of scale, although the UK can potentially play a lead role in its ability to design, specify and integrate complex systems.
11. Are effective measures in place to enable Government and industry to learn from the
outputs of current research and development and demonstration projects?
11.1 There are a number of initiatives and mechanisms in place for learning and dissemination of knowledge. They include a number of innovation support programmes, groups and forums, each with specific objectives targeting areas of importance.
11.2 DECC, working with the other Low Carbon Innovation Coordination Group (LCICG)
members, will use the LCICG’s Strategic Framework to help develop and co-ordinate future spending plans for innovation in storage and other low carbon technologies. The Department is also working with the LCICG to update the Group’s ‘Electricity Networks and Storage’ Technology & Innovation Needs Assessment (TINA) to recognise the economic and carbon reduction importance of storage research to the UK, along with Demand Side Response (DSR) and Smart Grids.
11.3 DECC has developed a paper with the ‘Smart Grid Forum’, which includes
representatives from Ofgem, electricity network companies, consumer groups, energy suppliers and the wider equipment supply industry, titled Smart Grid Vision and Routemap68, setting out a defined coordinated roadmap for the development and implementation of smart grid technology. Actions include developing a UK strategic direction, developing commercial and regulatory frameworks, achieving effective customer participation and promoting technological innovation and growth. Both Government and stakeholders support these actions and this approach.
11.4 In parallel, Government and other public agencies are funding a number of projects to
bring forward the deployment of the technology in the smart grid in a timely manner. These include several DECC’s Energy Entrepreneurs Fund projects that are developing hardware. For example, DECC are co-funding Kiwipower Ltd in a £975k project to develop a smart grid interface to building management systems that will be trialled in the Marriott hotel chain in London. Other projects are looking at developing cheaper interfaces to smart appliances and smart heating controls. In addition, Ofgem are funding trials of smart grid DSR technology through its Low Carbon Network Fund (LCNF) competition, and the Technology Strategy Board and the Engineering and Physical Sciences Research Council (EPSRC) are jointly investing up to £11m in a programme of collaborative research and development to stimulate innovation in localised smart energy systems.
68 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/285417/Smart_Grid_Vision_and_RoutemapFINAL.pdf
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11.5 DECC is currently providing significant innovation support for energy storage
technologies: further innovation is needed to reduce the technology costs to make storage technologies applicable for wide deployment. Different storage technologies are likely to be optimum for particular applications depending on their operating characteristics. DECC is currently supporting 7 research and 4 large-scale demonstration energy storage projects – with a total budget of about £18m. DECC’s current innovation projects are supporting a range of different storage technologies, including: cryogenic (liquid air) storage; Li-ion and other metal-ion batteries; flow batteries; pumped hydro storage in novel locations; and power-to-gas storage. DECC expects to publish details of its current energy storage innovation projects when they are concluded. Annex A lists some of the innovation funding awarded for storage innovation.
12. Is the current regulatory and policy context in the UK enabling? Will a market-led
approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
12.1 Ofgem will cover this question in their response as the regulator. 25 September 2014 ANNEX A: Energy Storage Innovation Support DECC’s Energy Storage Demonstration Projects
Moixa Technology Ltd (awarded contract of £1.3m, excluding VAT), to install and demonstrate deployment of about 0.5MWh of distributed storage across 300 domestic sites. Moixa’s MASLOW system provides night storage for electricity through Meter Attached Storage, to power low voltage LED lighting and DC electronics during peak periods. The system can store energy from local solar or regional wind resources to provide back-up resilient power, helping to keep the lights and computing online.
REDT UK Ltd (awarded contract of £3.0m, excluding VAT), to build and test a 1.2MWh vanadium redox flow battery system on the Isle of Gigha to store surplus wind energy for use in the local electricity network when required.
EValu8 Transport Innovations Ltd (awarded £2.8m contract, excluding VAT), on behalf of the EVEREST Consortium, to develop a new storage system, partly made out of recycled batteries from electric vehicles, which will store renewable electricity generated at times of low demand for use at times of peak demand to provide EV fast-charging capability;
Viridor Waste Management Ltd (awarded £8.1m contract excluding VAT), to work with Highview Power Storage to develop and demonstrate a large-scale - 5MW/15MWh – demonstrator of the Highview liquid air energy storage system. The demonstrator will be built and tested at a Viridor landfill site where it will use waste heat from landfill gas engines to increase the storage system’s efficiency. The system will be connected to the grid to test provision of balancing services using energy storage.
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DECC’s Energy Storage Component Research & Feasibility Study Scheme projects
AMT-Sybex - £308k for new optimisation & control system to manage multiple storage assets.
C-Tech Innovation - £500k for improvements to soluble lead redox flow battery components.
ITM Power Ltd - £507k to develop novel alkaline membrane electrolyser for use in a reversible fuel cell.
Quarry Battery Company - £204k study looking at the potential for wider deployment of new pumped storage facilities in novel sites.
EA Technology Ltd - £104k for Good Practice Guide for use of electrical storage in electricity networks.
Kiwa Gastec at CRE - £400k to investigate the use of hydrogen as an energy storage vector.
Sharp Laboratories of Europe Ltd (£396k to develop and scale up new battery technology for residential and community scale storage systems.
Other UK storage R&D projects
EPSRC allocated £30m in 2013 to create dedicated R&D facilities to develop and test new grid-scale storage technologies.
£14m ETI investment in 2011 to enable Isentropic to build & test 6MWh/1.5MW storage system at a Western Power Distribution substation in the Midlands.
Under its Low Carbon Network Fund, Ofgem is supporting several pilot projects which involve energy storage systems. The largest of these is a 6MW battery project being developed by UKPN at a substation in Leighton Buzzard.
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Government: Department of Energy and Climate Change (DECC) – Oral evidence (QQ 17-28)
Evidence Session No. 2 Heard in Public Questions 17 - 28
TUESDAY 21 OCTOBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Lord Hennessy of Nympsfield Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Peston Viscount Ridley Lord Rees of Ludlow Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston ________________
Examination of Witnesses
Sarah Rhodes, Head of Energy Resilience, Department of Energy and Climate Change, Craig Lucas, Head of Engineering, Department of Energy and Climate Change, Andy Shields Head of Security of Electricity Supply, Department of Energy and Climate Change
Q17 The Chairman: Could we reconvene? I welcome colleagues from DECC who are joining us once more, familiar faces here. Could I start by inviting you to introduce yourselves? If you would like to make any opening statement, please, feel free to do so.
Andy Shields: I am Andy Shields. I am head of the security of electricity supply team in DECC. My responsibilities include the design and implementation of the capacity market and short-term security of supply.
Craig Lucas: I am Craig Lucas. I was slightly mis-billed in the intro document there. I am the head of engineering for DECC. My responsibilities include looking at cross-cutting engineering issues for the department and I am also the programme director of the DECC Innovation Programme.
Sarah Rhodes: Good morning. My name is Sarah Rhodes. I am the head of energy resilience in DECC, which means that my brief is supply disruption, supply breakdowns, both avoiding them if possible and dealing with them if they occur.
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The Chairman: Thank you. Would you like to make an opening statement or shall we go straight into our questions?
Andy Shields: We will just go straight in.
Q18 Lord Hennessy of Nympsfield: I declare an interest: I am a fellow with the British Academy. I am not sure how that touches electricity but it is meant to touch everything, so I will declare it in case. Can I ask Sarah a resilience question to start off with? In general, how resilient is the system? I wonder if your answer could cover the implications for the next two winters and the outages that we have been talking about and know about, including the new one yesterday and also how we got into this position of relative vulnerability. Also, insofar as you can safely in public, please talk about the cyber threats and the critical national infrastructure problem and the degree to which the Chinese and the Russians—just to take two countries at random—could do considerable damage to our grid, to encourage us to be more pliable in other ways. I know that is delicate for a public session but if you could range across all of that, I would be very grateful.
Sarah Rhodes: Sure, yes, I am happy to. There is a lot in there. First, on resilience, the system is pretty resilient. When we compare it to international comparatives, it stands up well. We have a system that is proven in operation to be reasonably reliable. That does not mean to say that every problem can be mitigated. There are all sorts of threats to the system around weather, accidents, fires, as we have seen, hostile attack, technical failure—there are all sorts of things that can go wrong. They can be mitigated, but it is impossible to avoid any form of risk. At the end of the day you have to balance issues like affordability and resilience. There are a whole set of issues there to be balanced.
In terms of electricity outages, we have seen a few lately. In fact, this cluster of events is unusual. You do not usually see three fires, for example, this close together. There are all sorts of questions to ask around that, but there is no reason in fact to suspect that there is anything particularly sinister behind this or there is any more than a simple conjunction of events, although we and the electricity industry will be looking at this very carefully.
The incident at Didcot, again, appears to be a simple fire. The fire is now out, as of about 5 o’clock yesterday afternoon. The engineers are on site to try to establish what was the cause of it and, indeed, how bad the damage is and how long it will take to restore the one unit. The second unit is working as usual. At this point there is nothing to suggest that either the cause of the incident or the time to restore the unit are particularly concerning, but it is very early days and RWE do expect to say something on that later this week. I think that answers many of your questions.
Coming on to cyber, there is a lot of work going on with the industry, with DECC, with the security agencies to analyse the cyber systems, to define what is critical national infrastructure and to establish the degree of vulnerability protection to this threat. It is not a new threat, but it is a fairly recent one. The industry does not start from a position of being unprotected—quite the opposite. The industry is probably ahead of the game relatively.
But what we are doing is ensuring that there are audits done by the security services of the resilience of each critical piece and it is like the layers of an onion—you start with the centre and you work your way out. A lot of mapping is going on as to how the system operates, where all the links are and a lot of work is going on, both with individual companies and
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collectively, to establish things like minimum standards but also to make sure that each individual business is resilient, so there is a lot happening.
Lord Hennessy of Nympsfield: Would I be right in thinking that, since the last period of severe outages, if somebody came back from the Civil Contingencies Secretariat of those dreadful years of the 1970s and they listened to you and they read all your stuff, they would say that the range of threats has all gone one way—it is not exponential but it is noticeably all one way? Do you have any technologies that you can cheer us up about that might be visible now, almost touchable, that will reduce our vulnerability over the next 10 years, which is what we are looking at?
Sarah Rhodes: Looking at the historical parallels, in fact the system has steadily got more reliable. There have been increases in resilience across the whole piece. There is no magic answer to this. There is simply the business of learning from analysing threats, analysing incidents, exercising and looking at risk factors and just trying to ensure we know a little bit more each time.
Lord Hennessy of Nympsfield: What worries you most as an individual, because you have to carry the can? You will not get sacked, but as resilience in DECC you will be before Select Committees and people will be deeply offensive to you if it all goes wrong.
Sarah Rhodes: I fully accept the accountability for that and I am just noticing that the last answer was in terms of “Who do you shoot?” You are not short of people to shoot. What worries us most? Obviously the big one for electricity is a black start, where you lose the whole system. It has never happened to us. It has happened in other places. We do a lot of work constantly on how do you start up again because that is not entirely a straightforward exercise either. It is making sure we are absolutely ready for the big one. But there is generally no shortage of things you can worry about if you choose to.
Q19 Baroness Manningham-Buller: Can I just make an observation that is rather naughty? I do remember the case when the IRA was going to destroy the electricity in London, taking out all the electricity substations and in all of this we did not think very much about that. I want to ask you about the balancing system. We had quite a helpful explanation from the last speakers about how this works. Could you tell us whether you think it is going to be sufficient for the next few winters?
Andy Shields: Do you want me to take that one? Just to explain the process going ahead, in 2013 Ofgem produced its capacity assessment that suggested margins were going to reduce from reasonably high levels—or in fact very high levels over the past few years—to something around a more normal level of capacity. But for the next two winters, the winter of 2014-15 and the winter of 2015-16, there were some particular risks around the level of capacity that we would have on the system. As you have heard already, National Grid is procuring some additional balancing services for these two winters. That would get us back up to a level where we can have confidence and comfort that the margins are going to be okay over the next two winters. The analysis suggests that margins will begin to be even more comfortable towards the end of the decade.
Baroness Manningham-Buller: What would make you uncomfortable about those margins when you say the system gives you confidence? What could change that?
Andy Shields: I do not think you can ever have 100% confidence that any electricity system will be able to deliver. You see short-term events, particularly around storms and weather,
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those types of events or you can build resilience against them but you cannot protect 100%. In terms of the amount of capacity available to the system, you could see major systemic events, as you saw in Fukushima, but regarding the types of outages that we have seen recently—a fire at a particular power station—the system is generally resilient against those.
Baroness Manningham-Buller: One of the things this Committee is trying to get its head around—perhaps I should not speak for the Committee; I am trying to get my head around—is the market forces here and the policy interventions of Government and whether one distorts the other. Do any of you have any observation on that on this subject?
Andy Shields: The major driver for investment in capacity and ensuring that capacity is available at a particular moment is the electricity market. It is demand and supply and recently Ofgem has moved to improve the price responsiveness of the electricity market. We already start from a position where the signals are there for capacity to be available in tight situations. You look at what has happened historically over the interconnectors and, when we do see periods of high demand in Great Britain over the winter, you see electricity being drawn to the UK, and that should give us confidence.
As I say, with Ofgem’s reforms in this area and with the third package of EU legislation that has been brought in recently, we should see even more price responsiveness. The market is generally sufficient for that short-term measure. Where we have seen problems—and that is why the Government has developed the capacity market—is the potential for longer-term investment in reliable capacity. The concern there is that you will not get enough of this reliable capacity being brought forward without some type of intervention in the capacity market.
Q20 The Chairman: The supplemental balancing reserve, effectively and quite sensibly, rewards people for being ready to operate rather than selling their product but, of course, what is also needed alongside that is demand management. Do you think that we have sufficient incentivisation towards demand management or is this a bit of a Cinderella, do you think, compared to standby generation?
Andy Shields: In terms of the short-term measures that National Grid is introducing, there is both a supplemental balancing reserve and a demand side balancing reserve. There are two products there, one of which is traditional generation and the demand side is obviously focused on the demand side. That can be back-up generation but it can also be load reduction. There is a new product out there for the demand side, but it is fair to say that there is significant space for more capacity to come from the demand side and there are a couple of things here to point out.
The first is, looking at experience in the United States where they have had capacity markets and capacity mechanisms for a number of years, you tend to see a very significant growth in the amount of demand side that participates in those markets after the introduction of capacity mechanisms. In the GB capacity market, the demand side is eligible to participate and the first auction will be held in December of this year. In addition, there will be two bespoke auctions held just for the demand side held in 2015 and 2016 and the explicit purpose of those auctions is to help grow the capability and capacity of the demand side sector. With those interventions you should see an increase in the amount of the demand side response available over the coming years.
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Lord Peston: I am a little lost. We were told by the earlier witnesses that, for example, if there was an outage on a grand scale, the City of London might well close down for the day because it is all electric. I must say that would not break my heart—the country would be a lot better off. Does the back-up generating capacity of users like our hospitals fall within your remit? You were alluding to it in your last answer.
Andy Shields: The back-up generation resilience is for Sarah; I am more of the market and the incentives.
Lord Peston: Right, but does it fall within your department’s remit?
Sarah Rhodes: Yes.
Lord Peston: My obvious second question is: how do you fulfil your remit about that or do you leave it to the hospitals and so on to do what they need?
Sarah Rhodes: We have a whole set of processes that come into play if there is a shortage. Those processes are there to protect essential users, they are very regularly dusted down and that priority-users list is updated on a very regular basis. Alongside that we also expect key users to have their own business continuity arrangements so that they do not start completely unprotected. But, clearly, in the event of a big system issue then it is very much a question for Government working with the sector to ensure that electricity flows to where it is needed.
Q21 Lord Broers: What do you think these reserves should be? I note that the National Grid has sought out a demand side balancing reserve of 319 megawatts, which is less than 0.5% of the national peak load. What do you think is sufficient? What would you like to see those reserves at?
Andy Shields: Government last year decided to introduce reliability standards within the electricity system. That was done primarily to inform how much capacity to buy in the capacity market. That reliability standard says that there should be no more than three hours’ loss of load expectation in a year. Let me just be absolutely clear there: what that does not mean is three hours of black-outs a year. It is three hours where the system operator begins to take action to keep the system in balance. If you look at that reliability standard you then ask the question: given what is predicted to happen to capacity margins in the next couple of winters, how much additional balancing services do you need?
You are right to say that National Grid is already procuring some demand side balancing reserve. It ran a tender for some additional balancing reserve over September. It will announce the results of that, I believe, on Tuesday—certainly early next week. That will tell you the volume of additional services that is being put into the reserve. But I do not think it will be jumping the gun too much to say that what that will mean is there will be sufficient reserve to meet the Government’s reliability standard through this winter.
The Chairman: On the capacity market, do we have anything more on that?
Lord Broers: Yes, the question here has already been dealt with to a certain extent, the question being: will the new capacity market be effective at balancing supply and demand in the medium term and is there a risk that the capacity market will support too much capacity? It has already been said what we are worried about perhaps is an open-ended opportunity for suppliers to make a bit more money by supplying more than we need and so on.
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Andy Shields: The way that the capacity market works is it is a tool to ensure that we have sufficient capacity in the future. The first step is to make a prediction of how much capacity we will need a number of years ahead. You then run a competitive auction for all types of capacity to participate in, so you get the most competitive outcome. The winners of those auctions have to promise to be available in the year that we want them or they face financial penalties. In that way we ensure that the capacity is there able to generate.
The question was around: how do you make sure that we are not buying too much capacity? Clearly, the big issue here is you are making a forecast four years ahead of what electricity demand and the amount of capacity that you need is going to be and things change over those years or can change over that period. What we have done is said that we will buy some capacity four years out and then one year ahead, when we want that capacity in place, we will also hold a second auction to be able to top up if demand is increased, for example, if there is higher economic growth, or we buy a little bit less in that one-year-out auction if demand has not risen as expected. In that way you ensure that you should be pretty much where you need to be and that you are not over-procuring capacity.
Lord Broers: Another concern is: how likely is it that the capacity market will prolong the life of existing coal stations and what are the implications for carbon emissions?
Andy Shields: The capacity market is technology neutral. It allows generation, be it gas, coal or nuclear. It allows demand side. It is new and existing capacity all competing against each other on the basis of cost. We do not expect the capacity market to discriminate. In terms of what the future for coal is, clearly, there is a need for coal in the short term to keep the lights on and to keep the lights on effectively. But as you approach the medium term, as one of your previous speakers was suggesting, there are things within the market that will make it increasingly difficult for coal to generate.
You have heard about the LCPD and the IED. The fact that we are bringing on a very significant amount of low-carbon capacity will push coal higher up the merit order. Similarly, things like the carbon price floor will do the same. By the time you reach the mid-2020s there will be a very small amount of coal capacity generating and by the time you get to the 2030s it is likely there will be no coal at all. In terms of what the capacity market itself and the three-year contracts that are available will do to decarbonisation, all the scenarios suggest that decarbonisation targets will be met.
Viscount Ridley: Just quickly on that, a cynic might say that the capacity market is a euphemism for subsidising fossil fuels as well as renewables, because the effect is that if I am running a gas station but I am bidding for the capacity market—that is, to be available but not to run the whole time—I am going to bid a higher price than if I could run it the whole time in the absence of renewables.
Andy Shields: What the capacity market does, essentially, is it buys the total volume of capacity that you need. The electricity market will send us signals as to which capacity is called and which capacity gets to sell electricity, be it gas or any other fuel. The question is probably getting at whether you need gas to back up wind, and to some degree the answer is yes, you do need—
Viscount Ridley: But you end up paying more for the gas than you would if it was not backing up wind.
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Andy Shields: If you just relied on a system of gas you would have different costs in there. I do not have the figures and the answer, but obviously there are volatile gas markets, there are resilience issues around relying on just one type of fuel.
Viscount Ridley: But, other things being equal, if a gas station is running less of the time it is going to charge a higher price.
Andy Shields: Yes, that is true.
Q22 Lord O’Neill of Clackmannan: We are going to move on to contracts for difference, which you might say is the other side of the coin. We are told that contracts for difference should encourage low-carbon investment. In the first instance could you tell us how you imagine and how confident you are in contracts for difference making a difference for the timely investment in low carbon?
Andy Shields: I will. I am not the person responsible for CFDs, but obviously I know some amount about it, so I will just put that out there upfront. You are already seeing a number of contracts under the final investment decision already being allocated. I think we are talking about £12 billion-worth of contracts already signed. That represents about 4.5 gigawatts of new capacity being brought on by the CFDs. You then have the first allocation round, I think, taking place in December. That will bring on more. So we are already seeing very significant interest in CFDs, and we are already seeing contracts being signed. Hopefully that answers the question.
Lord O’Neill of Clackmannan: You are telling us you could have a clutter of these technologies. Mr Lucas, is there anyone in the department trying to establish whether or not this market process is coming out with the kinds of answers that we want? Rather than just volume, are we getting quality as well?
Craig Lucas: I will declare an interest: I am a fellow of the IET as well. We have a central model called the dynamic dispatch model that looks at that supply and demand balance and looks at the generation merit order. In the process of writing the EMR delivery plan, we gave that whole model to National Grid and asked them to take it to pieces and QA it. Because they operate the system, they could inform us whether we had made any mistakes in our assumptions. There were some quite robust discussions about some of the assumptions in it and it has been improved as a result.
The modelling we have shows that we have a mix of technologies. It is partly to do with the way that CFD budgets are allocated. That is more a policy question rather than a technical question, but the modelling we have shows that we do get a mix of technologies. We can have a sighting shot of what that mix is but we are not trying to lead the market. In general the answer is, we do have a fair idea and it is balanced. I do not know if you want to add to that?
Andy Shields: I can only say that the policy intent is to ensure that we support a range of technologies. Ultimately, as has been seen through solar, the cost of those technologies comes down and then you are in a better position to procure those that are better value for money and more resilient.
Lord O’Neill of Clackmannan: We have had the experience of solar, where prices have collapsed and, as a consequence, the need for a subsidy has been reduced. Is this system going to be sufficiently flexible—I do not want to use the word “resilient”—to accommodate
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radical changes in markets in the manner that we have seen in respect of solar generation in the last couple of years?
Andy Shields: If you mean the system whereby contracts for difference are allocated, the proposal is to move on a staged basis to a system where you have competition between technologies—we are already seeing some of this in the first allocation round—based on price. There is a staged plan to get there and that is the ultimate end game.
Craig Lucas: The other element to that is in areas like solar PV, where we see it as a very fast-moving market with some very dynamic things happening with pricing, we—my department and the Office for Renewable Deployment, who are not here today—regularly collect evidence about connection applications and things from the market. Then we filter that and look at it. We get that evidence from Ofgem and from the network businesses as to what is going through the planning and consent processes so we have an understanding of how we think the market is evolving.
Q23 Lord Willis of Knaresborough: It does seem to me that the conversations we are having on this question bring us back to the first panel, because there is so much interconnection between each of your roles in terms of answering the question of resilience, market supply and so on. I wonder whether, within DECC, you have approached this idea of total systems engineering so that all the bits are brought together for consideration. Is it an attractive proposition to DECC, is it actively being considered and, if not, can you explain perhaps why you are not considering the things in the system as a whole?
Craig Lucas: We are considering it. We set up an internal project probably about a year ago to look at the system issues holistically. That involves our economic analysis colleagues, it involves the engineering people and it involves those people that build models for DECC. We have a head of modelling and we have a suite of tools and models that we use to set our policy suite. The way that we have approached that is at two levels. One level is looking at the electricity system and what we see as the key resilience—partly resilience but they are partly market evolution—questions emerging for the electricity system. We have also looked at it at a more whole system level. So there are some bigger questions, like what proportion of it is going to be electrified and what is the evolution of electric vehicles and so on. We have those two work strands that are going on as underpinning evidence for all of the work that is going on in the policy space, and we have a number of academic partners working on them with us. Certainly some of the work that the IET has been doing is feeding into that as well.
We have various fora where we can talk to stakeholders in the industry, like the Smart Grid Forum. There is the Energy Network Strategy Group and various other fora where we can test, with industry, whether our emergent understanding of the issues is correct or not. Some of the players in the industry have very good data but none of them has the complete picture, so we are trying to draw that together in a more holistic way and it informs the way that we build and specify our modelling as we improve our understanding of how the market is developing.
Lord Willis of Knaresborough: Do you see this as your responsibility, and will there be anywhere where this will be published for scrutiny and examination?
Craig Lucas: We certainly see it as our collective responsibility as DECC, as the analytical leads in DECC. I am one of the analytical heads in the department. I am not sure we have
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thought through how we publish that and when, because we have been very much at the stage of defining what the key questions are and how that affects our internal work programme.
Q24 Lord Rees of Ludlow: I would like to ask about the particular problem imposed by the growing dependence on renewables. In particular, to what extent does the rapid growth in intermittent renewables present challenges to resilience, and how do you think we can reduce these challenges?
Craig Lucas: There are a few different facets to that, and I will treat them in no particular order. One of the first things you can do is look at the way you forecast. It takes four hours to start a large gas plant from cold, so if you can improve your accuracy of forecasting four hours hence you can operate more efficiently. There is a whole piece about operational approach and data and evidence, and that is one set of solutions. The National Grid is looking at that very hard.
A second area is looking at flexible technologies, and in that bracket there are probably four. We have touched on demand side response; we have touched a bit on electricity storage in some of the earlier evidence. Flexibility of generation comes in two flavours. It is possible to buy thermal generation that is more flexible than the legacy plant that was built 20 years ago. The specification of thermal power plants evolves. As we have been developing our thinking, we have been talking to manufacturers of generation plants about how that works and what that looks like.
In addition, if you look at the renewables generation, the people that build and specify renewables generation are increasingly being pressured, not just in the UK but in other markets, to minimise its impact on the grid. So the technical capability of renewables generation is evolving as well. There are things that, for example, a wind farm can do, if you buy it today, that were not required in people’s conception of how it would interact with the grid before, but that will be an evolutionary process.
There are also things about how we use interconnection. Again, with power electronics and with the evolution of the high-voltage DC technology, there are things you can do with interconnectors now. For example, the east-west interconnector with Ireland is a much more flexible animal than the England and France interconnector. The challenge for us is all these things are evolving, they are all part of our landscape, and it is constantly understanding what technology readiness levels they are at and how they might influence the overall game plan and eventually bring essential products to market.
Lord Rees of Ludlow: The long-distance DC grids have clearly been a good thing, but what about other ways of storage—batteries, capacitors and all that? Are you optimistic that they could be game-changers at any time?
Craig Lucas: We would love them to be. I would qualify that by saying that I personally have been involved in storage for a long time and it still has to get down the costs curve. That is the fundamental challenge with it. When DECC looked at storage, there are a number of technologies. Briefly, there is the electrochemical battery world; there is the electromechanical world of fly-wheels and things of that nature; there are other thermal processes; and then there are other physical processes like compressed air and hydro storage. We felt that the challenge is to get those technologies up the technology-readiness curve and ultimately drive the cost down. That is why we put £20 million of innovation
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funding into demonstrating some of the different technologies at scale to see where the cost reduction potential is, because technically they are all there—you can technically integrate them to the grid—but they are still too expensive.
Lord Rees of Ludlow: Slightly off the mark, could you say something about CCS? If we had CCS, of course, all these problems would be eased. Is that going to come on in a reasonable timescale and be economic?
Craig Lucas: Again, the technology for CCS exists. We have a company we are working with who are building a demonstrator in Texas and they are going to pump the CO2 down a well and earn money for it. The technology does exist. The main technology risk in our whole chain demonstration—I am not the CCS team, so I am paraphrasing from an engineering point of view—is in understanding storage in our geology. But the power station and the CO2 process engineering is relatively well understood. Part of the challenge from that process is understanding how to make CCS generation flexible, and that will greatly increase its value to the grid. But, yes, we do see it as a potential game-changer and that is why we have committed to run the CCS competition.
Q25 Lord Broers: Can I ask a rather general question? When it comes to safety and building roads there is a number that enables one to decide whether one is going to do something that is expensive but makes it safer. It is an awful number and we do not want to talk about it. It is something like a life is worth £400,000 or something. Do you think you are going to the point where there is a number like that for resilience? One can always go on improving resilience and improving resilience, but there has to be a financial limit. To be intelligent about this issue, one has to, in the end, try to come up with a number.
Craig Lucas: I think that comes back to value of lost load. Do you want to add to that?
Andy Shields: The reliability standard that I mentioned before essentially does that. It trades off the cost of additional capacity against the potential costs of disruption. I believe last year DECC put out a paper that explained exactly how that cost trade-off had been taken and the decision made on the reliability standard for the electricity industry. We can certainly send it to the Committee.69
Craig Lucas: I would just add it is based on the economic cost not on the immediate loss of energy. It is an economical methodology that assesses the cost to the economy, through a series of econometric experiments. It is a recognised methodology. There are other methodologies.
Lord Broers: That would be very useful. Another very quick question: if the market price of electricity goes above the strike price, is the consumer going to see any of that?
Andy Shields: I am not the CFD policy lead, so I will have to take that one back; apologies for not being able to answer it today.70
69 The report can be found at: https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224028/value_lost_load_electricty_gb.pdf. 70 Text supplied after the evidence session: Under the terms of the CfD, when the strike price is higher than the market reference price, the generator is required to pay the difference (multiplied by the volume of generation) to the CfD Counterparty (the Low Carbon Contracts Company). Any payments received from generators will be paid back to electricity suppliers
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Q26 Lord O’Neill of Clackmannan: What aspect of resilience is the supply of, for example, gas? There have been debates about whether or not we have a sufficient storage capacity. Indeed, there was a recent court case which has thrown out the judgment of one of your Ministers in the last few weeks. Are you reconsidering this question of gas storage facilities in the UK, given what has happened? Obviously, if you do not have adequate supplies of gas, then gas-fed power stations could come under threat, or businesses that use gas for power generation would be put in some difficulty.
Sarah Rhodes: Shall I take that one? We do look very closely at gas storage. Is there enough? There is obviously a very lively debate out there. I think it is constructive to look at the experience of March two years ago when the weather was unexpectedly cold and there was a huge surge in demand at the end of the season, when storage is bound to be relatively low. What we did see was that prices went up significantly, but we also saw, in a sense, the market acting as it is expected to do. As the prices go up, they draw in gas supply and the system was sufficiently supplied. So we do look very closely at the system in operation, because, after all, if we start building more gas storage, that has to be paid for. Again, we are trading off whether there is enough resilience in the system versus whether there is a case to put in more cost in order to buy yourself more resilience. We do keep a very close eye on it, not least because, as you say, we occasionally lose judgments and are forced to revisit our decisions.
Lord O’Neill of Clackmannan: What you are saying is that the system works provided the price mechanism operates and, at the end of the day, it is the consumer who pays for that. You have a responsibility to the citizen as a consumer as well as someone who wants to keep the lights on, and whether or not the gas storage capacity is sufficient to avoid these quite extreme changes. Other countries seem to be able to operate their system with fewer of these changes—these radical price spikes—but do so at the cost of having greater supplies of gas.
Sarah Rhodes: You are absolutely right, and the price equation, the question of what is affordable, is absolutely about whether it is cheaper to pay for the occasional price spike—and whether that is going to work to provide you with enough fuel—or whether it is cheaper to put more storage in. At the moment we are still in the former: that it is cheaper to pay for the odd price spike as long as we continue to have confidence that the market will deliver. But you are right that is the decision to take.
Lord O’Neill of Clackmannan: The concern is that the spike goes up very quickly but takes rather longer to come down.
Sarah Rhodes: We watch that very carefully.
Q27 The Chairman: You will have heard at the end of the last session evidence from IET that they favoured a new systems architect. I think the answer you gave Lord Willis suggests that you feel you are on the case within DECC and that you have the capacity to do what they are suggesting is required. Would you like to comment on the specific proposals of IET for a systems architect?
in accordance with their market share through the quarterly reconciliation process. We expect that in turn electricity suppliers would pass such payments on to consumers through lower tariffs.
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Craig Lucas: Yes, I will. We feel that the IET have been very helpful to us in helping to break down the resilience problem into some tractable sub-problems, particularly the way that they have convened a number of the industry players in an impartial setting, as a professional institution can, to look at the issues.
As came across in the previous evidence, while they have identified and quantified a number of risks and issues, principally about the end-to-end performance of the system, they have not yet proposed what the institutional framework for that might be. I would characterise the issues in two ways. One is that there is a set of technical things that we need to understand better, and that needs better modelling and better data and better technical expertise around them. That is a kind of advice point, an evidence point. Another point is then whether that leads you to taking any action to change something; that might be regulations or it might be standards or it might be the remit of somebody in the market.
On the first point, the way that we are thinking of approaching it is that with Innovate UK we are setting up a body called the Energy Systems Catapult, and its business plan is to look at the system integration issues of the energy system. We have been having a discussion with the catapult, as part of writing that business plan, that there is a work stream there for them to do to become a technical centre to look at those types of issues.
In parallel, there are other pieces of work we have been doing. We and the Government Office for Science commissioned the IET to do a study of the way that different people model the electricity system in particular. Understanding that these new challenges are emerging and the way that people model and share data might not be adequate for them, we have asked for a horizon-scanning piece that they are in the process of drafting with some of the industry players as well. What we are intending to do is to land that as a work programme in this new vehicle called the catapult, which would then give us an evidence base so that we could then look at it and say, “Does that inform our policy and regulatory landscape to do something different?”
Lord Peston: I am still a little lost. Our previous witness had this image of an architect, which was a hypothetical thing, which meant they would look at what that architect did. That would be my understanding of what they were saying. But then the architect has to get transformed into either a person or a committee or something. Am I to understand that you are working on that transformation and taking evidence on it? Because as at least one of my colleagues said, we would like to be able to report precisely on that as part of our eventual report. I am not clear what the architect is in the first place. I had assumed it was someone who would optimise, or something like that, within the criteria that gets set up. Can you enlighten us at all on where you stand as a department on that sort of thing? In particular, can we assume that the one person who will not be the architect is your Secretary of State?
Craig Lucas: We have not formed the policy position yet, to be really frank, but we are looking at all the issues that IET have raised—looking at whether they are issues that are effectively about centralising expertise and coming to a common understanding of the problem or whether they are more directive issues about the need for someone to control things differently. The outcomes that you might suggest would be quite different. It is a piece of work that we need to do. I do think that it is essentially a technical function and not a role of policy.
Lord Peston: Are you then telling us that, if we were to say something on this, we are on our own?
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Craig Lucas: I think the line we are taking at the moment is that we welcome where IET are going. There is some real evidence there. How it moves forward we are not sure, but we are very keen to be part of the conversation.
Q28 Lord Willis of Knaresborough: My apologies, Chairman, for jumping the question earlier; I had not reached to page 6. I think this is an endless piece of work. The complexity of creating a piece of architecture that is decipherable by policymakers is such a massive task that it could go on forever. It is such an attractive proposition because systems engineering in all different forms is something that we are particularly bad at as a nation. We tend to have a silo approach to things. What would interest me is if you could advise the Committee as to what you think the priorities would be within that architecture. While you might create a very elaborate and intricate building, you actually start with a number of key places, particularly in terms of the foundations. I think at least this Committee ought to be able to examine and recommend where the starting point for that should be. How it ends up, what form it takes and who in fact runs it and owns it is something for immortal beings, not just humans.
Craig Lucas: I will try to start that discussion. One of the things is that the IET have defined a series of resilience challenges. You can then work down from them and say, “What things do we need to understand to answer those challenges?” There are clearly some things about different approaches to modelling the problem, so there is a stream of work around that. There is a stream of work around who has what data in the market, how they share that data and how they talk to each other, so that is a strand as well. Then there is another strand about, if you have started to identify the challenges, what mitigating actions you might take. They might be about things like codes and standards and you might start looking down that route as well.
There are several technical work streams that drop out. There is also a technology and innovation work stream about how you integrate all the new things that are coming into the system, including things like smart metering and demand side response as well. Then there is a policy and regulatory strand that comes out of it that says, “As we see how these things interact with our system, how do they challenge the policy and regulatory frameworks that we have?”
I would say as well that DECC at a top level recognises that the smart technologies question is something we should have more of a policy view on. We are going to set up a small internal policy team to look at that in a cross-cutting way from the policy perspective and look at the value to the consumer, so we are approaching from that perspective as well.
Lord Willis of Knaresborough: It would be enormously helpful to the Committee if you could articulate what you have just said, and those other elements, within a short document and let the Committee have it. In answering the question that the previous panel rightly put to us, it would be useful to say that this is a direction we should be travelling in and these are the elements that should be on that early part of the road.
Craig Lucas: Yes, that is fine.
The Chairman: I am going to bring it to a close now. It is the allotted hour for the conclusion. I reiterate what Lord Willis has said on any follow-up help you can give us. We will be taking evidence, as you know, for the rest of this calendar year or so, so there will be an opportunity, if you have further evidence, to submit it. You will, of course, also have an
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opportunity to correct the written record so far as it is factually incorrect. It will be sent to you. On behalf of the Committee I thank the three of you for some very helpful evidence.
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Government: Rt Hon Ed Davey MP, Secretary of State for Energy and Climate Change, DECC and Jonathan Mills, Director, Electricity Market Reform, DECC – Oral evidence (QQ 186-198)
Evidence Session No. 16 Heard in Public Questions 186 - 198
TUESDAY 20 JANUARY 2015
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Baroness Sharp of Guildford Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston
_________________________
Examination of Witnesses
Rt Hon Ed Davey MP, Secretary of State for Energy and Climate Change, DECC, and Jonathan Mills, Director, Electricity Market Reform, DECC.
Q186 The Chairman: Welcome, Secretary of State. We are delighted that you have been able to join us for this, our last session on the inquiry that we have been involved in now for some weeks on resilience of our electricity generation and supply. I should alert you to the fact that we are being broadcast, so I will ask you just for the record to introduce yourself. If you want to make an opening statement in any shape or form, we would be very happy to hear that. Otherwise, we will go straight into the questions.
Rt Hon Ed Davey MP: Thank you very much Chairman. I very much welcome the Committee’s inquiry. This issue is obviously vital to electricity security of supply, and I welcome proper scrutiny of what we are doing. I am delighted to have Jonathan Mills, who is director of electricity market reform at DECC, here with me today. I do not think I need to say much more than that, and I look forward to your questions.
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The Chairman: Thank you very much. During the course of our inquiry we have recognised that there are a number of conflicting objectives in delivering resilience to UK electricity. There is the question of affordability, of security and of decarbonisation. Ultimately, how reliable you want the system to be must eventually be a political decision, balancing costs overall with the ability of bill payers, and for that matter of taxpayers, to match the implied costs. So my first question of a general kind is: who do you recognise as ultimately responsible for maintaining resilience in the electricity system—keeping the lights on—and do you feel that the electricity market reform introduced by this Administration has brought back unduly large-scale government intervention, or do you feel that the balance is about right?
Rt Hon Ed Davey MP: First of all, inevitably Ministers are responsible for the overall policy design and, as the Secretary of State for Energy and Climate Change, clearly I am responsible to Parliament for the design of policy on energy security and resilience in the electricity system. But we obviously work with industry, and industry delivers on an operational basis, whether it is the long-term planning for investment or the day-to-day managing of the system. Clearly the lead on that is with National Grid, which we work closely with. National Grid is, of course, regulated by Ofgem, which, on behalf of consumers, has to ensure that the balance is right between the costs and ensuring that consumers get the supplies they need, because that is obviously fundamental to what consumers want. National Grid and Ofgem are the key people we deal with in designing policy. We have worked very closely with them and continue to do so as we estimate what needs to be done and design policy. Then, of course, you have the wider industry, whether it is the generators or the distribution and network operators that own and operate the regional electricity networks. I am fundamentally responsible, of course, but we work very closely with industry and the regulators to deliver a secure system.
Your other question was whether or not electricity market reform has seen more intervention. Clearly it has. The first reason for intervening in the market that lies behind EMR, and indeed behind policies before it that were similar but not as well designed, is in my view the need to tackle the challenge of climate change. The market does not cost in the effects, the costs, of climate change, and while you might want to do this in another way, for example through a carbon price or carbon tax—we know the difficulty of designing those both internationally and with a credible level over time—we think that the contracts for difference, which is our intervention on the carbon challenge in the EMR, are a good way of dealing with that problem. They are a targeted intervention.
The other major intervention by the electricity market reform is, indeed, on the security of supply through the capacity market. It has been clear for some time that, left to its own devices, the free market was not bringing forward low-carbon capacity or sufficient capacity, so the capacity market within EMR is designed to do that. But it is quite common in the academic literature to find two good reasons for intervening, which have emerged both over history and in different countries, and they are the two I mentioned: the need to deal with the fact that the markets do not price in carbon by themselves and do not have a solution for that—they will just bring in fossil fuels and not low-carbon—and the need to make sure that we have security of supply.
Q187 The Chairman: You referred to the contracts of difference, which offer different levels of support for different types of renewable technology. As I understand it, they are to offer
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greater levels of support for technologies that are at earlier stages of development. But in practice it seems that they fix the price of electricity for a certain technology, and it does not seem to disappear once this technology has matured. Clearly you are not going to have a free market. In any way, the free market does not seem to have been able to deliver the capacity that we now seem to recognise we need. After all, the capacity market is subsidising the restoration of what would otherwise be redundant capacity. Why did the market not signal the need for new generation?
Rt Hon Ed Davey MP: There are two questions there, and if I may I will unpack them. First, on the contracts for difference, you are right that as we deploy the budget in the levy control framework, we support less mature technologies in a greater way by the very fact that they are less mature and need extra support. If we did not, you could end up with a suboptimal outcome for the country, and indeed the world as a whole, given that those technologies could turn out to help us dramatically in a more cost-effective way. An example at the moment might be carbon capture and storage, which is not happening to the extent that people had hoped, and the need for government intervention to bring that technology on is clear. But I have to disagree with you about the design of electricity market reform and how it is affecting prices on the supply side. Legislative market reform is in several phases. The first phase is having strike prices at an administered level, in the way in which renewables obligation certificates worked. Phase 1 is very much about administered prices. Phase 2, which we are going to more rapidly than we expected, is technology-specific auctions—we have various pots: pots for more technology and pots for less mature technology—and we are bringing market forces into the selling of those contracts for difference far faster than people had expected and than we had expected. So you will see the support costs—the subsidies, if you like—for these new technologies falling as market forces help to deliver that.
Ultimately we want a free low-carbon electricity market where the subsidies are no longer. It is possible—we have seen the trajectory of the costs of some of these technologies—to envisage that in the next decade, and I hope we will move from a technology-specific approach with these different pots to a technology-neutral approach.
Q188 Lord Broers: Are the Government confident that sufficient action is being taken to keep the lights on, especially over the next two years? We have heard evidence that today’s tight capacity margin was entirely predictable. How has the UK ended up in this position? Is this simply a case of policy failure?
Rt Hon Ed Davey MP: When the coalition came to power, it was very clear that we were going to have to run as fast as we could to ensure that the lights stayed on, not just in the short term but in the medium and long term. We were left with a legacy of underinvestment in our electricity system and we have had to take short-term, medium-term and long-term measures. The long-term measures are about bringing on all the extra capacity, whether that is low-carbon or gas capacity. We have seen in the first three years of this Parliament—I do not have the latest figures; we hope to publish them later this year—more than £45 billion of investment in electricity generation and networks, which is a dramatic increase in the level of investment. We published a report in July last year setting out energy investment across the piece, which can detail for the Committee how that big surge in electricity investment has occurred. That is really for the long term. In the long term we are looking at about eight of our nine nuclear reactors probably coming off line by 2023. We are looking at
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almost all our coal generation going by the middle of the next decade. So we must have a long-term strategy.
We need a medium-term strategy for the end of this decade, when we will face particular challenges. The capacity market, which I am sure we will come to, is very much focused on that. Your question focused on the short term and the next two winters. To take the measures that we agreed, and which we have been planning for several years now, given the legacy we had—it is not a new thing or a sudden realisation that there is a problem—we have used the powers in the Electricity Act 1989 and consulted on them with National Grid and Ofgem to bring in supplemental balancing reserves on the supply side and demand-side balancing reserves on the demand side. We have pushed ahead with that, so for this winter, 2014-15, National Grid has purchased 1.1 gigawatts of balancing reserve to support the system. It has not had to use that at all, because we have got nowhere near a problem, but it is there; it sits outside the market and National Grid can use it if we have a problem at peaks. We do not anticipate that, but it is there as a sort of insurance policy. We are expecting there to be about 1.8 gigawatts of supplemental balancing reserves for 2015-16. On the basis that that goes ahead, I am sure that the lights will stay on not only this winter but next winter as well. That action—which, as I say, has been planned with all the different stakeholders for a period of time—can give this Committee and the public the reassurance they need that the lights will stay on.
Lord Broers: That has all been a little last minute, has it not? And it has not been cheap; I calculate that it is going to cost £1.26 billion.
Rt Hon Ed Davey MP: First of all, it has not been last minute, as I have sought to set out for you already. These plans have been developed since the coalition came to power. I do regret that there has been a poor legacy, but we have been working on it. If you look through the history of our consultation and our announcements, they have not been just in the last week, month or year, but over a period of years. So I do not call that the last minute. Of course they come at a cost—absolutely. My job has been to make sure that we minimise that cost. Jonathan may be able to remind me of the cost of the supplemental balancing reserves for this winter and next, if he has them to hand. We will come to the capacity market in a second, and that is expected, over the lifetime of those contracts, to add about £11 gross to anyone’s bill—but when you take into account the fact that wholesale prices will not peak at such high rates as they otherwise would have done, the net cost of that intervention is just £2 on the bill. So, having been given a problem to tackle by previous Governments, we have gone about it in a systematic way, over time, and done it in a way to minimise the cost to the bill payer.
Jonathan Mills: The figure for the supplementary balancing reserve is less than £1 on the average household bill.
Lord Broers: But the situation is getting more and more difficult, is it not, given the way we have tackled it? It is inevitable now that our electricity is very expensive. We have been slow in realising the real supply that will decarbonise electricity because nuclear has slipped and slipped. I am surprised that you seem confident that we will have—did you say eight new nuclear plants?
Rt Hon Ed Davey MP: No, I said that eight are closing by 2023. I cannot tell the Committee that we will have eight new nuclear power stations by 2023. Eight are closing, and we need to fill that gap.
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Lord Broers: That is quite aggressive, considering that we have made almost no progress on any of them.
Rt Hon Ed Davey MP: I have to say that I completely disagree. We have spent a huge amount of time on this. The last Government put some of the framework in place. We are months, possibly weeks, away from signing the final contract for Hinkley Point C with EDF. That will be the first new nuclear power station in a generation. It has gone through a whole range of processes, such as the regulatory process to generate generic design assessment, the planning process and so on, and we have two other consortia that have either gone through the regulatory process approval—the GDA process—or are a long way through it. They are, of course, Hitachi with potential nuclear reactors on Anglesey and at Oldbury, and Toshiba and GDF Suez with a nuclear reactor in the north-west. So if you talk to people around the world, and certainly around Europe, we are seen as a country that has grasped this nettle and has been moving far more quickly than others. We have a very detailed policy that looks at decommissioning and waste management in a way that previous generations—I underline this—failed to do. We are not repeating the mistakes of previous generations.
Lord Broers: So you are confident that we can meet our three requirements of security of supply, cost and competitiveness, and decarbonisation?
Rt Hon Ed Davey MP: Our three objectives are the ones that you have said, and I believe that we are managing them. I will take them in turn. On decarbonisation, we are seeing a reduction, in electricity in particular, of our fossil-fuel sector. We are seeing a big increase in renewables. If we add that to nuclear, we are seeing record amounts of low-carbon electricity as that rolls out. We need to do a lot more, but there is real progress there. We could talk about heating and transport, which is not going quite as fast as electricity, but your report covers electricity and we have made a lot of progress there.
On security, I believe that we now have a very systematic approach in place for the short, medium and long term to give people that reassurance. While the report covers not just electricity security of supply but other aspects of energy security of supply, I would recommend to the Committee the report by the US Chamber of Commerce, which looks at energy security across the world for its member companies to invest in. It places the UK as the most energy-secure country in the European Union—Norway is slightly higher than us, but in the European Union we are the most secure. We are the fourth most secure country in the world. The three countries ahead of us are Norway, as I mentioned, New Zealand and Mexico. I do not know why Mexico is more energy secure than we are; I have not looked at it. But it means that we are more energy secure than the rest of the European Union, the United States of America, Australia, Canada, Japan—I will not go on to list all the other countries in the world—and so are not doing quite as badly as some of the headlines you might read. So that is decarbonisation and energy security. By the way, I do not want to come across as complacent—we are watching this all the time—but the idea that we have not made progress here is something that I contest very strongly.
The final point is about affordability. This is something that I worry about all the time, but you have to look at it for both domestic and business, because the pictures are slightly different. On the domestic side, our gas prices in the UK for households are the lowest among the EU 15 comparator countries. Our electricity prices for domestic households are among the lowest. So if you have those international comparisons, our prices are among the lowest. I focused on making sure that electricity markets are among the most competitive,
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and I am sure you will be as delighted as I am to see that yet another big six company has reduced its prices.
One of the challenges, though, is for industry. While industry has relatively low gas prices, it has relatively high electricity prices compared to other European countries. We need to work on those, as indeed we are doing. I am working with my right honourable friend the Secretary of State for Business, Innovation and Skills, and the Chancellor, on a whole range of policies to support energy-intensives that otherwise would have competitive issues, given the relatively higher price of electricity for industry in this country. I could go on at length about the ways in which we have tackled affordability for both domestic and business customers, but I think I have made my point today—although you may wish to come back on this.
Lord Broers: In terms of competitiveness with America we are not very well off, are we?
Rt Hon Ed Davey MP: You are right to say that. The shale gas revolution has absolutely changed the energy price comparator with the United States, but if you compare us with the rest Europe, and indeed with the rest of the world, it is not quite as severe, as they have not enjoyed the benefits of the shale gas revolution in the way that has happened in the United States. When one looks at the impacts and how you address them, they are more on energy-intensive industries, because, on average, energy costs are about 3% for the average manufacturing firms; the petrochemical and steel types of industries are particularly exposed. I have argued at the European Council, as well as within the Government, that we need to have a strategic response to the competitive challenge that shale gas applies to the UK vis-à-vis North America. That strategic response has a number of elements to it. The first is securing and completing the single energy market in Europe, which will put much greater downward pressure on prices. One thing I have championed as Secretary of State has been interconnections with our European neighbours, because that will produce lower prices and greater security in the long term.
We also, across the European Union, need to look at R&D and innovation. I particularly wanted to bring that to the Committee’s attention. It seems to me that there is a case for greater European effort on R&D to help energy-intensive industries. I hope, whether it is in Horizon 2020 or other budgets, that we can do more as the European Union—indeed, more as a country—to work with energy-intensive industries to make not just marginal changes in their efficiency and efficient use of energy but step changes. In the European Union ministers’ group I set up something called the green growth group, which now has a corporate platform for businesses to talk to European Ministers about all these issues. At some of those meetings we have heard from energy-intensive industries across Europe about how they are beginning to think in this way. The example that I was particularly impressed with was the European federation for paper and pulp, which is a big, energy-intensive industry. It has run a competition to look at the different technologies that could be transformative over the next 15 years. It believes that some of those technologies, with some support from the European Union and member states, could be taken so that they could reduce their use of energy by 50%.
The point I am making to the Committee, with respect to your question on competitiveness with America, is that we have to have a strategic response to that. We cannot just wring our hands. That strategic response is, first, the single energy market and, secondly, R&D.
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Q189 Viscount Ridley: Can I press you a little further on the affordability leg of the trilemma? You took comfort a moment ago from the fact that energy prices in this country will not peak as high as you thought they would. This is largely because of the downward pressure on fossil-fuel prices from the fall in the oil price, the shale gas revolution and so on. But at the same time you have said that we are about to sign a contract for Hinkley C, which many people, even in the nuclear industry, regard as an extraordinarily highly priced nuclear facility. We are pressing ahead with offshore wind, which is three times the price of gas electricity. Is there a danger that the falling price of gas and oil is exposing a real gap in affordability behind the agenda of decarbonisation and security? Your predecessor had, I think, three scenarios for what would happen to fossil-fuel prices and they all went upwards. They varied just in how much they went up.
Rt Hon Ed Davey MP: Let me first for the record say that I am not complacent about prices; it is something that we focus on, laser-beam like, all the time. Let me take issue with your points and start by commenting on what is happening to oil and gas prices. Oil prices have more than halved in a very short time. This will impact particularly the transport sector. It will have almost no impact on the electricity sector and almost no impact on heating, because, in the main, oil and gas are not substitutes; they may be at the margin, but generally it is very rare to find oil-powered electricity stations—I am not sure that we have any more. We might have them in the reserve. Oil is not seen as a way to produce electricity any more. On heating, it is mainly people who are off the gas grid who use oil for heating. The dramatic decline in oil prices is not affecting gas and electricity prices.
Viscount Ridley: No, but we talked a moment ago about the fall in the gas price as a result of the shale gas revolution.
Rt Hon Ed Davey MP: I am coming to that, but there is quite a lot of misinformation. The dramatic collapse in the oil price will not impact oil, gas, heating and electricity so much. Of course, the fall in wholesale gas prices is affecting those prices and is welcome. Let us look at what has happened. In the last year, the average wholesale price—depending on which price and which date you take—has fallen by between 20% and 30%. It fell quite dramatically in the first half of last year and then crept up significantly. So it has been volatile, but over time it has been on a downward trend, which I welcome. It will actually help the decarbonisation agenda because it will help us to remove coal from the system much more quickly. If there is one part of the decarbonisation agenda that we have to pursue relentlessly it is to remove unabated coal from the system. Rather than hindering the decarbonisation agenda, I argue that it helps it in the short and medium term.
You then brought in whether the costs of the contracts for difference are at one with Hinkley Point C—the first new nuclear power station—or offshore wind. Taking Hinkley Point C first, given our policy we have been pretty rigorous and robust in calculating the price that we propose to close the deal on with other comparators, whether that is gas plus the cost of carbon—that is important if you are going to compare apples with apples and not apples with pears—and other comparators such as onshore wind, taking into account the system costs that they might have, which is not the case for nuclear. I think we published our analysis when we did the heads of terms of agreement and we will certainly publish it when we conclude the deal. I think you will find that rather that it being expensive in the way you suggested, it is good value for money when compared with alternatives. Would I like a lower price? Of course. Are we pushing hard for lower prices? All the time. Some people look at the wholesale price of electricity and compare it with Hinkley Point C and conveniently
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forget that oil and gas are not paying the price of their pollution. That means that you are not doing the right comparison.
I could make the same comparison for onshore wind, but it is slightly different. Hinkley Point C would represent a third generation of nuclear reactors—very mature technologies that have been around for many decades. Offshore wind is a new technology. What we are trying to do, through our system of intervening through electricity market reform, is drive down the costs of offshore wind. Our target is to get it down to £100 per megawatt hour by 2020. We have worked with the Offshore Wind Cost Reduction Task Force; it is pretty clear that we are going to do that. If you talk to some of the investors and developers, such as DONG, they are even more aggressive than that. So for a pretty new technology, in which Britain is leading the world and has huge potential, we are driving those costs down far faster than many people have recognised. Inevitably, you can pay higher prices when you are rolling out new technology, but I would have thought that this Committee, more than any other, would have recognised that you do not take snapshots when you deal with technology; you look at technology development and deployment over time.
Q190 Lord Winston: Obviously we are very pleased to hear about security, but can we turn to major events? What are the emergency plans for worst-case scenarios? How are they developed, tested and co-ordinated in case of a major event? How much are exercises on the emergency procedures for serious or catastrophic failures of the grid carried out?
Rt Hon Ed Davey MP: Electricity, gas and transport fuel are a major part of wider government planning for dealing with emergencies. The Government, with their cross-sector national risk assessment, are looking at hopefully every conceivable type of risk to the UK, and I pay tribute to my right honourable friend the Minister for the Cabinet Office, Oliver Letwin, who has held the ring for a lot of work that this Government have done. I do not think it is appreciated by many, because looking at all this resilience planning is not terribly sexy, but he has done it more thoroughly than it has ever been done before. My responsibilities are quite a big subset of that. We deploy our planning under the national risk assessment mainly through the Energy Emergencies Executive, the so-called E3, which brings together government, industry and regulators, first to identify the risks, then to try to prevent them and mitigate them—obviously prevention is better than cure—and planning for what happens if our prevention and mitigation strategies do not work. We will look at everything from severe weather events to terror attacks, cyberattacks, technical failure and industrial action to plan how we would manage in those circumstances. We will then produce documents, strategies and policies, which might be directly linked to our investment strategies so that our networks in the UK are some of the most resilient and effective in the world. Our reliability rates for our networks are 99.99%71—we will give you the exact figures later. They are incredibly reliable, but we are absolutely not complacent; we still need major investment. I published a major report recently on that investment, which is all about prevention. We also plan ahead in case something happens that we could not have invested for. We have a national emergency plan for downstream gas and electricity and a national emergency plan for fuel, which set out what would happen in an emergency.
Lord Winston: Are periodic rehearsals conducted?
7171 This figure is for transmission, rather than networks as a whole (i.e. including distribution).
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Rt Hon Ed Davey MP: Yes.
Lord Winston: How many have you personally been involved with?
Rt Hon Ed Davey MP: I personally, in terms of my time, have been involved only with one. I do not have a figure for the Committee today for how many there have been. I know there have been more than the one that I was personally involved in, but Ministers tend to be involved at different levels, with junior or Cabinet Ministers in some of these exercises.
Lord Winston: We have heard quite a lot of evidence on the risks of cyberattack. What are you doing about that scenario?
Rt Hon Ed Davey MP: From the Cabinet Office to No. 10, across government, there is a major effort to look at cyber issues. We have seen investment in the key transmission and distribution mechanisms, but because it is an evolving threat and one that we take very seriously, we do not think that we reached a final solution for dealing with cyber and we keep it under constant review. Jonathan, did you want to add anything?
Jonathan Mills: I was just going to say something about the number of exercises involving electricity that have been conducted. A large number of scenarios that might be primarily about testing some element include lots of electricity suppliers as a dimension. Without giving confidential details, electricity is considered a dimension in a large range of scenarios that are tested.
Q191 Baroness Sharp of Guildford: Can I bring us back to the capacity market? Are you satisfied that the Government are now meeting the trilemma of a secure, low-carbon and affordable electricity system? How do you decide how much capacity to procure? Are current security standards fit for purpose, and what are the risks of basing policy on current standards rather than looking ahead rather further? Is there a risk that the capacity market will report too much capacity and cost consumers more than it should?
Rt Hon Ed Davey MP: First of all, the process of determining how much we want to purchase in the capacity market involved a huge amount of consultation—indeed, we had recommendations from National Grid, after it had worked with the department, with Ofgem and with industry. That was related to loss of load expectation, which is a new way of measuring it—it is a bit like old margins, but we think it a more informative and helpful way of measuring what you are trying to achieve—and that was after that had been debated and consulted upon. We spent some time working out how much we felt we needed to contract for. Our analysis suggested that we needed about 48.6 gigawatts—that was our target. We ended up buying slightly more than that, just because it made sense and was good value for money. We ended up buying 49.26 gigawatts in the first capacity market auction, which was the clearing price of £19.40 per kilowatt hour. Interestingly, that was significantly less than the figure in our impact assessment. When we did our analysis, we thought that we would end up having to pay about £42 per kilowatt hour, but I am delighted to say that the capacity market produced a much better price, from the consumer’s point of view, at less than £20. That is why the cost to the consumer is less than we had expected.
There are a number of parts of the capacity market auction that are worth bringing to the Committee’s attention, because they were pretty successful. Not only will some plant be maintained on the system and its life extended, which is economically and environmentally a good outcome, but it has unlocked new investment; we have seen a large independent gas plant at Trafford win a contract in the capacity market. So in terms of security, the capacity
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market auction was a success. Clearly we will do a review of how it went and learn lessons that we will take on board for next year’s capacity market auction. At a high level, it looks as though it has done the job and at a more competitive price than we had expected.
That links into your other question, Baroness Sharp, about low-carbon. The capacity market itself is not an intervention to deliver low-carbon; the contracts for difference are. We had the first round of contracts for difference with what was called the final investment decision enabling contracts for difference—we do not make it easy for ourselves with these words. We issued eight of those contracts to five offshore wind and three biomass projects, which will stimulate £12 billion of private sector investment in low-carbon. We now have the first enduring CfD round with that auction under way. That should complete in the coming weeks, and we expect to allocate up to £4.5 billion of support to another wave—
Baroness Sharp of Guildford: Has that first auction not given a disproportionate amount to old and rather polluting plant?
Rt Hon Ed Davey MP: First, that was the intention: to keep old plant on the system. It is quite economically sensible to sustain the life of a gas plant and prevent it from closing too early. That is one of the aims of the capacity market.
With regard to polluting plant, I have seen some of the commentary on this, but the commentators do not seem to understand how long these contracts are for. The vast majority of the contracts are one-year contracts, for 2018-19, so to the extent that they are keeping on coal plant they are keeping it on for a year.
Q192 Baroness Sharp of Guildford: What about the demand side? Is there enough emphasis on the demand-side response?
Rt Hon Ed Davey MP: We certainly have demand-side balancing reserves and we are working up demand-side response. We still have some way to go on that side. We have had some success, but we want to do more. Jonathan might want to comment on that. It has not been the major part of this work, but I am very keen to look at it.
Baroness Sharp of Guildford: Clearly the more we can smooth out the peaks, the greater the advantage.
Jonathan Mills: We modelled the approach that we have taken here quite closely on international evidence, including from the United States, where we have seen demand-side response play a very large role in markets such as the PJM market. We allowed demand-side response to participate both in the auction that we have just conducted, on the four-year ahead market, and in the one-year ahead market, which we will conduct, to top up, if necessary, any gap between what we have procured and what we need. We got about a gigawatt’s worth of interest in the T-4 auction, which I think was positive. We would really expect more of the demand-side response to seek to participate nearer the time, because the evidence suggests that the economics of attempting to sell demand-side agreements on a shorter time horizon tend to be better.
We had some success in T-4, but we look to T-1 as our real opportunity for that technology. With that in mind, we have put special transitional arrangements in place to enable demand-side response providers to prepare for future auctions. Those are open only to demand-side response providers. We hope that we can mirror the sort of patterns that we have seen in the PJM market, a market that is about three times the size of ours. It went from about two
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gigawatts in its first demand-side auction to 20 gigawatts now. There is potential for that sort of growth.
The Chairman: There is an imbalance here. You are concentrating on the one-year contracts for demand-side management and longer contract times for the capacity margin. Do you not need to think on a longer timescale for demand-side management?
Rt Hon Ed Davey MP: With respect, I think we are doing both. We have both T-4 and T-1, where the demand side can play in.
Jonathan Mills: On the length of contract available, we are trying to strike the trade-off between flexibility, getting the best cost for the consumer and ensuring that there are as many people able to participate and as much competition available as possible. The evidence that we had through the consultation was that while people in the demand-side sector understandably wanted the most favourable terms available, a one-year agreement was supportable and a realistic proposition that would enable people to come in. That is the basis that we have worked on. As the Secretary of State said, we will keep all aspects of the operation of the capacity market under review.
Baroness Sharp of Guildford: How do you write the possibility of price volatility, such as we have seen today, into your forward planning?
Rt Hon Ed Davey MP: The contracts for difference are stable prices over 15 years. The consumer is protected, because if prices go above the strike price they have to get back. We built that into the CfDs. We are trying to get the market to respond to the capacity market. Clearly, they are making commercial decisions. The good news for the consumer is that the price cleared much lower than we had expected.
Can I bring two distinct parts of the demand side to the Committee’s attention? There is the demand-side response, which is part of the capacity market. We are trying to get people to change their behaviour at peak demand to help with the smoothing out. But we also have pilot schemes, which we call electricity demand reduction pilots and are about permanent reductions, not directly related to this security challenge. We are trying to get demand-side responses in the market in peak management, but also more broadly in terms of long-term decarbonisation.
Q193 Lord Rees of Ludlow: To go back to the question of the adequacy of the 4% safety margin, we had different views from various witnesses on whether that was large enough to be comfortable. It is clear that it is enough to deal with the worst crises that we have had in the last decade. Do you agree that, in this context, the past may not be a good guide to the future, in the sense that there are new types of threats—cyberattacks and terrorism—and that we are getting more and more vulnerable to cuts in electricity, especially with prolonged outages? Do you really feel that you can reassure those people who feel that 4% is not enough?
Rt Hon Ed Davey MP: First, the margin for this winter is more than 6%. It was 4% before the balancing reserve measures kicked in, but that has given us additional margin. That is significantly above the standard that we set. In setting the standard, we took into account a whole range of different scenarios. When you do this sort of planning you look at what would happen if a nuclear power station did not function, or if there was some flooding that meant that a particular power station could not operate. We create scenarios that would be quite frightening, were they to happen. We try to ensure that the system is robust in a lot of
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those scenarios. No one can ever say that we can plan for the most extreme scenarios and I do not think that you expect me to, but on all reasonable planning, given that we have a cost issue here—we manage reliability and costs—we absolutely err on the side of caution, as you would expect us to.
Lord Broers: This is a very naive question: how on earth does this auction work? You receive bids from different sorts of suppliers at presumably all sorts of different prices. I am very ignorant of these things. Does one price emerge from all this?
Rt Hon Ed Davey MP: When we were designing it there were different types of bidding strategies that we could go for. We decided to go for the clearing price strategy. There are various rounds of the auction. First, the price is set and you see how much capacity you get at that price. If you get more than you need, you lower the price.
Lord Broers: I see. So you gradually set the price and look at the volume coming in?
Rt Hon Ed Davey MP: The auction took place over a period of days. It was not a one-off.
Lord Broers: Do you apply some sort of risk assessment to the people supplying it?
Rt Hon Ed Davey MP: They are entering a commercial contract. They have to prequalify and to do so they have to meet certain criteria.
Lord Broers: So you assess their credibility.
Rt Hon Ed Davey MP: Jonathan may want to say a bit more about the prequalification process.
Jonathan Mills: There is prequalification to ensure that people have deposits where they need them, that they have planning permission and all those sorts of pass/fail tests. The individual technologies are then subjected to a process of de-rating. They are adjusted for the average reliability of the technologies involved.
Q194 Lord Peston: My question is the counterpart to Lady Sharp’s set of questions. It is on the distribution networks. My understanding is that, both for households and firms, their experiences of disruptions or failure to supply arise mostly from what happens to the distribution networks. Most of them were as ignorant as I am; they just assumed that there is a switch, you get electricity, and that is your sole contact with the system, especially if you pay by direct debit, so you do not even have any contact with your supplier. What puzzles me is how the system works. We had the people from Ofgem here last week. They were very interesting, but I still could not make head or tail of what they were telling us because they used different words. At one point they said that the investment in distribution is supervised by Ofgem. Another thing we got was that it is regulated by Ofgem, which is not the same at all. A third was that Ofgem ensures that the distribution network has enough investment. It is the word “ensures” the puzzles me considerably. That relates to the question of where you come in. Do you just stay out and let Ofgem do it, or do you get involved?
Rt Hon Ed Davey MP: Ofgem is an independent regulator.
Lord Peston: Yes, I know.
Rt Hon Ed Davey MP: Under the third EU energy package, it needs to be independent. That helps to promote competition. With respect to distribution and network operators, its job is to do all the three things that you said. I would use all those words: regulate, supervise and assure. It does this through price control periods. It looks at what needs to be done. There is
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a whole range of different DNOs in different parts of the country, because they are effectively local monopolies. It discusses with them what investments they need in their distribution networks over that price control period. These tend to be quite long periods. The current one is from 2015 to 2023. That is seen as a real strength. I can say this, because I was not involved in setting it up—I am not bragging or anything—but the UK’s system of regulatory controls of DNOs is seen worldwide as a leader, because it gives great stability for investment. Therefore, we can get it at a lower cost. People from around the world have come to look at how we regulate our distribution network system.
Lord Peston: They also told us about something called RIIO.
Rt Hon Ed Davey MP: That is the price control system.
Lord Peston: But it is an incentive system.
Rt Hon Ed Davey MP: Yes it is.
Lord Peston: It is not a system that can ensure anything. Incentive systems give you the incentive, but that does not mean that you deliver. They can be adjusted then, so that they improve. Most people think they have a right to electricity when they want it, but they added, “If you pay for it”. So when I raised what was happening in Scotland at the very time we were talking, they said, “If you choose to live on the Isle of Skye and you don’t want your power supply interrupted, you have to pay for that”. Do the Government agree with that as well?
Rt Hon Ed Davey MP: We are not advocating a policy of free electricity.
Lord Peston: No, no, but people would not regard having a proper delivery system as free electricity. They regard electricity as paying their bill. They do not regard the capital cost as free electricity.
Rt Hon Ed Davey MP: Your bill has the wholesale costs in it: the costs of producing the electricity or buying the gas. It then has the cost for networks, which is the cost of investing, maintaining and repairing the gas pipelines, the electricity cables and so on. It also has elements for the administrative costs of the company involved and its profits. It has a small amount for helping us to deal with fuel poverty and a small amount to help us support low-carbon electricity. People are paying for the costs of the networks in the average bill.
Lord Peston: Yes. Wearing my economics hat I know that someone has to pay, but ever since I have been on this Committee doing this inquiry I have talked to people who of course know that they have to pay but who also think that they have a right to an assured supply; notice that they used the word “right”. That is what the people I talk to think about electricity. Those of us in public life have difficulty with people claiming that they have a right to this and a right to that. I just want to know your judgment. Do you have a judgment?
Rt Hon Ed Davey MP: Of course there is a very interesting philosophical position about political rights—
Lord Peston: Yes, exactly.
Rt Hon Ed Davey MP: —to a fair trial, free speech and so on, and to economic rights. I would simply say that in a modern developed country, people expect the electricity system to work. Let me give you some figures, which I hope will reassure you. Whether they get quite to your point about rights, I do not know, but in 2012-13 Great Britain’s national electricity
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transmission system operated with a reliability figure of 99.99975%. In 2013-14, that improved slightly to 99.99991%. I do not know whether that gets to a right, but it certainly suggests a very reliable system.
Lord Peston: I am not denying that. Speaking again wearing my economics hat, I would always round up and say 100%.
Rt Hon Ed Davey MP: I am happy for you to do that.
Lord Peston: You have covered the ground that I wanted you to clarify.
The Chairman: We will call that 100% and move on.
Q195 Lord Patel: The central theme of my question is on the resilience of the electricity supply. Various policies and measures that have been put in may well have an adverse effect on that. If it does, who will be held responsible for making sure that that does not happen? Let me give you an example. The electricity system is expected to change radically over the coming decade. What effect will that have? Will that adversely affect resilience, and who will make sure that it will cope? What additional policies and measures are required to meet carbon budgets beyond the mid-2020s? How might that affect resilience? What effect might reducing the diversity of the electrification of the whole energy system have? Might that decrease resilience? Lastly, although not directly connected, how much contribution can or should flexible generation, interconnection, electricity storage and demand-side response make to the integration of intermittent renewables? A whole set of different questions maybe.
Rt Hon Ed Davey MP: I think that what lies behind those questions is an acute observation that technologies are changing and that the ways in which we are going to produce electricity are going to change over time. As we move to low-carbon technologies, they will all have different features. Coal and gas are broadly seen as relatively flexible. Other types of system will have different features. Nuclear is seen as having a base load. Carbon capture and storage will enable us to have some of the features of gas and coal today. Renewables tend to have different types of features—some are intermittent; some, like tidal, operate in different ways. So as we plan the system and we have more low-carbon and different forms of electricity generation, we need to ensure that the system maintains the resilience and security that it has always had. That is one of the reasons why the objectives of energy policy remain the three that keep recurring. We place weight on all of them, and as we decarbonise we will have to ensure, and we are ensuring, that we focus on resilience and security of supply.
You asked me then to speculate on carbon budgets in the 2020s and 2030s. In a way, it is very difficult for me to do that, because one of our approaches to electricity market reform is to reduce intervention over time. At this stage, as we are dealing with developing technologies, it is quite interventionist, for reasons that we discussed right at the beginning. But the objective is to remove intervention gradually over time as costs come down and as low-carbon technologies compete. To give you a bird’s-eye view as I see it, I do not know which of the low-carbon technologies in the 2020s will be the most competitive. People might think it is a bit odd that the Secretary of State is not certain, but the thing I am certain of is uncertainty. I am absolutely clear that we do not know how these different technologies and cost profiles are going to change. We have created a very flexible approach to electricity market reform, which will in effect be a market in low-carbon, to enable the most
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competitive low-carbon technologies to develop. We could end up with nuclear being championed in the 2020s and more nuclear being built than other low-carbon technologies, or we could find breakthroughs in carbon capture and storage and see a massive expansion of that, or we may see offshore wind costs come down dramatically and be ultra competitive compared with the others, and we will see them taking a bigger share.
Whatever that market response is, we have to think about the impact on the security of supply in the system. It is not that we just have a completely hands-off approach; we will need to think through how having different shares of different low-carbon electricity will mean that the system behind it has to evolve. Clearly that is ongoing work. You show how dramatic this change is going to be. Many people do not really recognise that. We are not just talking about low-carbon in the electricity sector. The electrification point that you make in your question points to the fact that electricity may well be the low-carbon approach to decarbonising transport and heating, and if electricity is behind the low-carbon technologies for heating and transport you can imagine how much low-carbon electricity we are going to need in the future. We are going to need huge amounts. Imagine that we had no fossil-fuel cars, we all had electric vehicles, and we had to produce the low-carbon electricity to run 30 million vehicles in the country. That is a lot of power, in addition to the electricity needs of today. Clearly these are big, strategic changes, and it is quite difficult to be precise about them now, but we are going to have to think them through.
Your final point was about how we manage that, whether it is on the demand side or using new storing technologies and so on. For me, the alchemy for energy policy is storage. If we could find cheap ways to store electricity in particular but other forms of energy as well, that would be a massive breakthrough. Huge amounts of work are being done on that. Sir David King, the climate change adviser to the Foreign Secretary, is talking about his Apollo project: his idea that globally we put more money in together to sort out energy storage, because if we could store solar and wind power in very efficient, cheap ways, that would also be transformative.
I hope that in that bird’s-eye view I have given you a sense of the excitement and the sheer scale of what is happening, but also of the uncertainties and how policy has to try to manage those. I cannot give you a full answer about what the system will look like in 2030, because no one can.
Lord Patel: While I agree that all that is quite exciting as we move towards it, the key issue while we do that will be the resilience of the supply side. That was the key question: who will be responsible and how will they tackle the issue of ensuring resilience is always there?
Rt Hon Ed Davey MP: That almost goes back to the first question from the Chairman. Ultimately, whoever is doing my job has to think about the policy design to ensure that it can deliver that resilience, while working with industry, headed up by the system operator, which is National Grid. There is quite a lot of work and future scenarios that I am sure National Grid will have talked to you about, if it gave evidence to the Committee. People are thinking about these issues; we need to plan for them in our future scenarios. If you have too hard-and-fast plans for what the system needs to look like in 2030, you will almost certainly get it wrong, because the changes are quite profound and have quite large degrees of uncertainty.
Viscount Ridley: Following up on that, you are quite right that we will need a lot of R&D to work out what the position will look like in a date such as 2030. You said earlier that the
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falling wholesale gas price is helping decarbonisation because it is displacing coal. That goes to the evidence that we had from Professor Dieter Helm, who said that he would have preferred to see a policy of dashing for gas now, as that gets a quick, cheap decarbonisation of the electricity system—not full, but partial decarbonisation—and a lot of money into R&D for energy storage, CCS, nuclear and all these other things to see whether we can come up with longer-term solutions.
We have also heard evidence that the decline in the cost of wind energy has plateaued—we heard that from Robert Gross last week—and that wind requires a lot of system back-up, which means that wind is not delivering anything like decarbonisation. What would it take for you to give up on a technology such as wind and to say instead that we should be using gas now, with more in R&D for future technologies?
Rt Hon Ed Davey MP: The problem with a gas and R&D approach now is that you could be really behind the curve in some of the fast developing technologies. You are almost putting off the challenge, which is so great for the globe. It seems to me that we need to experiment not just in the laboratories but in deployment. A lot of lessons can come only through deployment. If you look at the cost savings in offshore wind—I do not believe that they have plateaued; I do not see that in the figures I see—they are all about industrialisation. They are not about something you do in a test tube, but about working out how you manage to put things out in the North Sea: securing them to the seabed, having bigger ships, improving the installation and so on and so forth. You cannot just wait and hope that R&D will sort that problem out; you have to do it.
Interestingly, in solar you need to do both. In solar you can look at and try to reduce installation costs, but some of the evidence from some of the labs in California shows that the costs of solar panels are falling even faster than we have seen. That is very exciting. I think that solar will be a very big player in the future. Many people think that the costs of solar will be lower than gas and coal in the relatively near future.
That is why I think that a boom for gas and R&D would be a wrong approach. The danger, particularly if you put all your eggs in one basket—that is a very bad idea; I am into diversity, not betting the planet on one particular technology—is that gas would become locked in. If CCS turns out not to work, you would end up having too much fossil fuel locked into the system, with all the dangers, risks and costs that that would entail for future generations.
The Chairman: Very briefly, Lord Ridley, then we must move on to Lord Rees.
Viscount Ridley: In which case, I will pass over.
Q196 Lord Rees of Ludlow: You mentioned in the context of decarbonising that nuclear may be the best bet in the long run. I would like to ask a bit more about nuclear. We all know very well that the level of expertise in this country has plummeted over the last 20 years, to the extent that any new nuclear power stations will be built by the French or the Chinese and not by us. This is very sad to many of us. The more realistic issue is the extent of our involvement in R&D. A couple of years ago this Committee had studied the level of nuclear R&D. It was dismaying that it seemed unclear whether we could even train the next generation of nuclear inspectors, so low was the level. The issue was taken up by the Government. I would like to ask how you see UK involvement, at least in R&D for fourth-generation and small-scale modular reactors, which is important.
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I would also like to ask about an issue that has just been brought to the attention of the Committee in a letter we had from Dame Sue Ion, the chair of the Nuclear Innovation Research Advisory Board, which was set up two years ago—it was good news when it was set up. She is now disappointed that in the recent spending review no money was allocated for the ongoing cost of nuclear in the Autumn Statement. Can you comment, maybe not on a particular issue but on the general issue of how much we can be involved in nuclear R&D and next-generation nuclear?
Rt Hon Ed Davey MP: Let me preface my remarks by saying that I have in the past been very sceptical about nuclear power, mainly because of its costs. Over many decades the costs did not really come down enough. I changed my mind and decided that the country needs to embrace all forms of low-carbon generation because of the threats of climate change and the costs that that will impose, and is imposing, on the world, now and in the future. I believe, given the sheer scale of the threat from climate change, that to discard any low-carbon technology, whether it is offshore wind or nuclear, is frankly deeply irresponsible. That is not a policy that we can have at this stage as we tackle climate change. I have embraced the prospects of nuclear power. I hope that we can get the costs down and learn from the frankly disastrous lessons of the past. Two-thirds of my budget is spent on decommissioning and nuclear waste management. That is its legacy. We cannot allow that to happen again.
We need to build up expertise as we go into new nuclear generation. I agree with you: it is regrettable, given that we were one of the leading nations in this industry in the past, that we no longer are. Again working with my right honourable friend the Secretary of State for Business, Innovation and Skills, we published, I think in 2013, an industry strategy for nuclear—for the supply chain, the skills and so on—to ensure that we build up our skill base, knowledge and, hopefully, intellectual property rights over new technologies. I agree with your overall proposition.
You mentioned that people felt that we did not spend enough in the recent Autumn Statement—it was not the spending review, it was the Autumn Statement. I have heard that. It would be inappropriate for me to tell you how the bidding process went in that Autumn Statement. However, I believe that the forthcoming spending review, which no doubt the next Government will have to undertake, will need to look at R&D for all low-carbon technologies and make it a priority, whether it is nuclear or others. On taking nuclear forward, whether it is small, modular reactors, which has a lot of press, or fourth-generation technologies as you call them—thorium or molten sodium—all of them need to be in the mix. Again, I am not going to sit here and tell you that I know which are the right ones, because I am not a nuclear scientist. A huge amount of uncertainty surrounds all of them. But given the huge challenge of low-carbon electricity for Britain and the world in the decades ahead, we definitely need to invest in this type of R&D.
Lord Rees of Ludlow: On this issue of Sue Ion’s committee and the anomalies that they have—£80 million capital allocation already, but not the running cost to make use of it—that does seem to be a serious weakness.
Rt Hon Ed Davey MP: I do not recognise the figure. I am sure that we can write to the Committee with some of the investments that we have made. The Secretary of State can certainly make decisions about spending. Quite a lot tends to be locked up already before you get a chance to look at the budgets, but at the end of the year you get an underspend
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and you think about how that can be allocated. Recently—I do not think it was last year; it may have been the year before—the chief scientist recommended that we spend money on a share in a nuclear test reactor that helps to test materials. He persuaded me that this was a very important part of future research, and we allocated some of our scarce resources to that. I have certainly been open to that, but, as I say, the next spending review will be critical for this and other decisions on energy R&D.
Q197 Lord Broers: I would like to follow up on R&D for nuclear. In this report, which was published in November 2011, the Government committed to going ahead with the various recommendations. One was that there should be a long-term strategy until 2050, another that a road map should be drawn up, and another that R&D should be funded at a higher level. Here we are, three years later. The problem with this is that there are several time-sensitive things. First, there is a lot going on overseas and there are a lot of opportunities to collaborate on those projects. Overseas, people were optimistic back then because they thought, “Good, Britain is backing this game”. We are not backing it, and now we are embarrassingly being left out of all this.
There is also the issue of skills. There was a resurgence for a while, but again that is lapsing. The population that knows about the nuclear situation is getting very old. This is a serious and time-sensitive situation.
There was also the anomaly, as Sue Ion points out, that £80 million of capital was provided for facilities and equipment but no money was provided for people to use it. We see this as an urgent and frustrating situation, because we felt that our report had had some impact and that things were going ahead.
Rt Hon Ed Davey MP: All I can say is that we keep this under review. We have put forward some money. We recently announced £67 million of investment in nuclear R&D infrastructure both through the Autumn Statement and through the separate grant exercise by DECC, so it is not that money is not being made available; £67 million is a sizeable sum. We have funded a feasibility study on SMRs, for example, and we have secured additional funding to investigate the further potential to the UK of deploying SMRs in the UK.
You mentioned international projects. In my previous answer I talked about a decision I made for capital investment in a state-of-the-art material test reactor, which is based in France. That was a £12 million investment, and it helped to provide the UK with access rights and R&D support. We have been doing quite a lot. Should we do more? Yes. Could we do more? Absolutely. But I am afraid that I come back to my point: in difficult financial times you will have noticed that we as a Government have had to make quite a lot of difficult financial choices. It will be the next spending review that sets the longer-term frame for this type of R&D.
Lord Winston: Secretary of State, I do not want to extend this for too long as I know your time is precious, but one of the things that we found very clearly—I have seen this myself as an academic at Imperial College—is much reduction in the number of people wanting to do PhDs or post docs in nuclear physics. It is also clear that the Engineering and Physical Sciences Research Council, which I sat on at one time, is unable to fund research in the way that it should do, with the reduction in research spending. I do hope that that can be looked at and that the commitment that was given is reinstated. It is very, very important if we are to invest in nuclear in the future. Would you just comment on that very briefly?
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Rt Hon Ed Davey MP: I want to reiterate my point that we recently announced £67 million of investment in nuclear R&D in the Autumn Statement and in our grant exercise. That has not necessarily had the attention that it deserves. I do hope that students choosing different engineering and scientific courses are clearly seeing the Government’s push on new nuclear; it is difficult to miss it. Whether it is the supply chain industrial strategy that we launched in 2013, or the work that a lot of the nuclear developers are doing with colleges, such as the college down in Somerset, which EDF has helped to support, there is quite a lot of activity here. When I go to the Nuclear Industry Council, which I co-chair with Lord Hutton—I cannot remember how many times I have been but I have been quite a few—one of the main items on the agenda is always skills and supply of labour. A huge amount of detailed work has been done to look at the number of people we will need at different skill levels. We are engaging not just with industry but with universities and colleges to work out how we deliver on that. I am sure that we can provide you with more material, but this is something that we are very alive to, and we are working actively and in close partnership with industry on it.
Q198 Lord Willis of Knaresborough: Secretary of State, the two things that I have learnt throughout this inquiry is that in the move to a low-carbon electricity system there is a great deal of uncertainty, which you mentioned this morning, and that it is a hugely complex field. There are many players in it, some with complementary demands but many with competing demands—of course, once you put the market in, there are competing demands. We were urged very early on by the Institution of Engineering and Technology that a systems architect was required to look at the whole system who could advise not only government but all the various players on a very, very clear road map. Do you think that that would be a good idea? If it is, do you think that the lead player as systems architect should be the Government, the National Grid or Ofgem? If it is not, what is the alternative?
Rt Hon Ed Davey MP: First, you are absolutely right on the uncertainty, competing interests and complexity. Ultimately the department is rising to that challenge, and my officials do a huge amount of work with academics and institutes that is all about thinking about the future. I certainly welcome the work that the Institution of Engineering and Technology and its energy panel have done in looking at this concept of the systems architect. That needs further exploration. I am not saying that we are yet convinced that it is the right solution, but I think they are asking the right questions, and we would like to see that work in that area and the governance of the system continue.
The Committee will be aware that we have an energy systems catapult as part of the Secretary of State for Business, Innovation and Skills’ programme for helping new technology and new challenges to be taken forward and dealt with more speedily. The new systems catapult can definitely explore the thinking behind the systems architect and work with the IET and others on a structured programme of work to explore the potential.
But as you hinted towards the end of your question, there are quite a number of players already, whether it is National Grid as the systems operator, Ofgem as the regulator, or DECC as the sponsoring department, so I am not yet convinced that we need a new body to come in. There may well be responsibilities and duties that need to be given to an existing body with an overall shape and role within the government system, but I am not in the market for a whole new set of quangos—I am not sure that that is needed. Some people have suggested that we need an energy security board. That looks like a totally unnecessary quango. The analysis behind the concept of a systems architect is where we need to go.
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What would it do? Could it be grafted on to one of the existing players? We are certainly not rejecting that. We want to see it explored, but it is relatively early days in working out what that will actually look like.
Lord Willis of Knaresborough: Just as a final comment, it is the first time that the energy systems catapult has been mentioned today. In other fields, there is huge excitement about the catapults. They have really taken off and are leading innovation in the way the Germans did with their Fraunhofers and what have you. I might be wrong, but no one has come to this Committee and said that the energy systems catapult is playing a key role here. Why do think that is? What do you think it is doing?
Rt Hon Ed Davey MP: It is very early to say. It is only just starting up, so if anybody had mentioned it I would be surprised. I cannot remember exactly when it was announced. We might have to write to you about it, but it was relatively recently.
Lord Willis of Knaresborough: It would be useful to have its terms of reference anyhow, so that at least we know what its core functions are going to be.
Rt Hon Ed Davey MP: Of course.
The Chairman: I think we can provide that and will circulate that for the next meeting.
On that note, we have reached the time when we assured you that we would let you go. Thank you for a very interesting morning’s session. I think we have agreed on one thing throughout: that there is uncertainty and complexity whichever way you look. Equally, we recognise that somebody, whether a new organisation or the existing players, has to help in trying to chart a road map through this complexity, which is driven by new technology, legislative programmes, affordability and much else besides. Whether our report, once it sees the light of day, helps to elucidate who should do that, only time will tell. Thank you very much indeed for helping us in our deliberations.
Rt Hon Ed Davey MP: Thank you very much for inviting me. I look forward to your Lordships’ report.
The Chairman: Thank you very much.
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Government: Jonathan Mills, Director, Electricity Market Reform, DECC and Rt Hon Ed Davey MP, Secretary of State for Energy and Climate Change, DECC – Oral evidence (QQ 186-198) Transcript to be found under Government: the Rt Hon Ed Davey MP, DECC
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Professor Richard Green, Imperial College London, Professor Gordon Hughes, University of Edinburgh and Renewable Energy Association – Oral evidence (QQ 80-90) Transcript to be found under Renewable Energy Association
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Professor Richard Green, Imperial College Business School – Supplementary written evidence (REI0050) Resilience of the Electricity Grid
1. This memorandum supplements my evidence from the session on November 18, including questions for which I prepared an answer but the committee did not have time to ask.
The cost of decarbonisation
2. The government is proposing to pay £95 per MWh of output from an onshore wind station commissioned in 2014-15 (in 2012 prices), compared to £155 per MWh for output from an offshore station.72 By 2017-18, these prices fall to £90 per MWh and £140 per MWh. A large solar PV installation (i.e. over 5 MW of capacity) would be paid £120 per MWh, falling to £100 per MWh. The headline figure for the price in the contract to be signed for Hinkley Point C is £92.50 per MWh, falling to £89.50 per MWh if a station at Sizewell goes ahead. The contract apparently contains gain-sharing clauses which would allow for a lower price if the construction costs are below those assumed in the headline price, and the European Commission’s decision on state aid has strengthened those clauses.
3. Similar contractual prices are not available for carbon capture and storage, but the latest DECC report on electricity generation costs73 estimates £107 per MWh for an advanced supercritical coal station with Carbon Capture and Storage and £95 per MWh for a Combined Cycle Gas Turbine with CCS. In contrast, the estimated levelised cost of energy for an unabated CCGT is £85 per MWh over its lifetime – the DECC projections are based on fuel and carbon prices that rise over time.
4. Levelised costs of energy for a single station operating in isolation are a very poor representation of the cost of the entire system. A large number of stations have to work together to meet the fluctuating demand for power, and many will not be able to run at the high load factors assumed in levelised cost estimates. It is therefore best to use a detailed system model, while recognising that its outputs are only as good as its inputs, particularly with regard to fuel price forecasts.
5. I have analysed results from a model built by Dr Iain Staffell and myself and used to provide evidence to an earlier select committee’s enquiry.74 This compared the
72 Department of Energy and Climate Change: Investing in Renewable Technologies – CfD contract terms and strike prices, December 2013, URN 13D/323. 73 Department of Energy and Climate Change: Energy Generation Costs (December 2013), URN 14D/005. The figures are taken from Table 4. 74 Gross, R, P. Heptonstall, R.J. Green and I. Staffell (2012) Supplementary evidence to the Energy and Climate Change Select Committee on the economics of wind energy, published online as ev57a to HC 517 of 2012-13, http://www.publications.parliament.uk/pa/cm201213/cmselect/cmenergy/writev/517/m57a.pdf.
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capacity needs and running patterns of a British power system optimised around 7 GW of wind capacity with those of a system optimised around 30 GW. An optimised model gives an indication of the long-run costs after the system has adjusted. During the transition, which can take years, operating costs may be higher because a sub-optimal mix of stations is in place, but wholesale market prices can be lower if additional renewable generation has created spare capacity before fossil stations are closed – this has happened in Germany, where it is known as the merit order effect.
6. With 7 GW of wind capacity, the total cost of nuclear, coal and gas generation came to £23 billion, including the cost of carbon at the current carbon price support rate of £9.55 per tonne. This is equivalent to £67 per MWh and broadly consistent with current wholesale prices. The time-weighted wholesale price is around £60 per MWh, but the demand-weighted price, which is a better reflection of the average cost of the system, is a few pounds per MWh higher.
7. With 30 GW of wind capacity, the optimised capacity of gas stations falls by just over 2 GW, since wind stations contribute little to meeting peak demand. This saves just £200 million in fixed costs, but avoiding over 30 TWh of gas-fired generation and 20 TWh of coal-fired generation cuts annual fuel costs by £1.8 billion, taking account of the cost of running stations part-loaded and of additional starts. The cost of carbon emissions falls by nearly £300 million at the Carbon Price Support rate, and would fall by £1 billion at the price of £30 per tonne originally announced for 2020. Overall, the costs of fossil-fuelled plant would fall by £3 billion a year.
8. Against this, 50 TWh of wind output would cost consumers around £6 billion at the CfD rates cited above, depending on the split between onshore and offshore wind. The net cost, around £3 billion, would be about 12% of the total cost of generation; the level of wind generation would increase by fourteen percent of demand. Carbon emissions would fall by around 30 million tonnes per year (one-fifth), although an economic value was already placed on this, by including the price of carbon in the cost of generation.
9. The model does not take account of short-tern uncertainty and cannot be used to calculate any increase in system balancing costs due to increased wind generation (although it does include a margin of plant running part-loaded to cover uncertainty, and the capacity that needs to be supported through the government’s new capacity mechanism). An IEA task force75 of engineering experts has reported that additional reserve (not necessarily actually running and hence incurring variable costs) equal to 10% of the wind capacity would be needed to cover the uncertainty in wind output four hours ahead. They estimate the cost of balancing to be €1 to €4.5 per MWh of wind output, or up to £3.60 at the current exchange rate. This covers wind generation meeting up to 20 percent of demand. In the scenario discussed above, the additional cost would be £200 million.
75 Holttinen et al (2013) Summary of experiences of and studies for Wind Integration – IEA Wind Task 25, in Proceedings of WIW2013 Workshop, London, 22-24 October 2013.
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10. The costs in Great Britain may be higher than this, not least because of transmission constraints. I have been able to approximately replicate Professor Hughes’ estimate (in his memorandum of evidence) that with unchanged demand, weather and transmission, National Grid’s balancing charges would rise by £700 million a year, with two caveats. First, mine was a purely statistical analysis based on regressions that capture only one-eighth of the daily variation in charges. Second, National Grid is planning and making investments that should reduce the volume and costs of constraints on its system.
11. I could not replicate Professor Hughes’ analysis of the cost of hedging volatility in prices. He suggests in paragraph 25 that 50% of electricity consumption might be hedged, and in paragraph 16 that the cost of hedging was in the range of £50 to £60 per MWh hedged. That implies a cost for hedging alone of £25 to £30 per MWh of electricity delivered - a number which is impossible to reconcile with the all-in price of £118 per MWh (plus VAT) paid by domestic customers in 2011-13.76 I believe that he misread an Ofgem chart that gave the average price paid by electricity suppliers after they had hedged in advance (the “hedged price”) to mean the price for the hedge and did not check the implications of this interpretation.
12. A better measure of the cost of hedging is the bid-offer spread on forward contracts, which measures the difference between the price that a retailer has to pay and a generator would receive – these prices would normally bracket their expectations of the price of power at the time the contract falls due. Ofgem has reported a spread of around 1% for Baseload contracts and 1.5% for peak contracts, or 60 pence to £1 per MWh. 77 Given that the expected cost of the hedge is the price paid for the contract less the expected price in future, perhaps half this amount, it is not surprising that retailers have hedged almost all their supplies in the past – the level of short-term trading in the British power market has been low ever since the Pool was abolished in 2001.
13. The level of price volatility can increase with the amount of wind capacity in the short term, but once the industry’s thermal capacity has adjusted to this, the change is relatively small. Even if this led to a doubling in the cost of hedging (and generators would presumably want to hedge as much as retailers), the cost to the retailer (at half of the bid-ask spread) would then be at most £1 per MWh or so, and only half of this would be additional. The extra cost would therefore be at most around £150 million a year (and probably much less), in stark contrast to Professor Hughes’ calculation of £3.4 billion.
14. Considering the cost of thermal plants and their operations as modelled above, the regression-based estimate of increased balancing and constraint costs (which may well be an overestimate) and a small allowance for hedging costs, the overall increase in costs would be at most £4 billion (with current fuel prices and carbon at £30 per tonne). The best way to reduce this would be to minimise the risks facing
76 Digest of UK Energy Statistics, Table 1.7. 77 Ofgem, 2013, Wholesale power market liquidity: final proposals for a ‘Secure and Promote’ licence condition: Consultation, Reference 88/13, figure 14.
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low-carbon generators, thereby cutting their cost of capital, and to ensure that this is passed on to consumers through the CfD prices.
Balancing services that wind can provide
15. Colleagues at a meeting of the EPSRC consortium “Transforming the Top and Tail of the Energy System” provided information on the balancing services that wind could provide. Wind generators are capable of providing fast frequency response downwards, reducing output within seconds in the event of a sudden fall in demand. They could also provide upwards response if they were deliberately set to run at a lower level than the wind allowed, increasing output when needed. This is the equivalent of running fossil-fuelled plant part-loaded, which is usually preferable because it saves fuel.
16. Wind farms can also be set to provide reactive power (needed in specific places to keep the voltage within limits across the system) and there have been experiments in changing their settings to vary the amount provided in real time. It is also possible to provide reactive power from the converter station that connects the Direct Current line from a distant offshore generator to the Alternating Current grid.
17. The power system needs the inertia that comes from the weight of spinning metal in thermal power stations to ensure that after a fault, the frequency with which every generator is rotating does not drop too quickly. Wind farms and solar panels are connected to the grid via power electronics and do not provide inertia. In the small Irish power system, there would be too little inertia if the proportion of thermal output fell below 50%, and wind stations are sometimes constrained off to ensure this. The British system is far larger, implying that we would normally have a sufficient absolute amount of inertia from thermal stations meeting a smaller proportion of demand. This would allow a greater share of wind and solar power at each moment in time; however, there may be a need for more detailed studies to determine the limits. There have been experiments with using the power electronics on wind stations to provide synthetic inertia, similarly slowing down the fall in frequency after a fault.
Perovskite Solar Cells (in response to Q87 from Lord Broers)
18. My colleague Professor Jenny Nelson FRS kindly gave me the following information on perovskite solar cells. This new material which is a lead halide perovskite containing small organic molecules as part of the crystal structure, was tried in thin film solar cells and over the last two years record efficiencies have increased to close to 20%. A lot of the leading work has been done by Henry Snaith at Oxford, and there is also a spin out, Oxford Photovoltaics, who are trying to develop the perovskites for semi-transparent windows. The EPSRC solar supergen consortium has adopted the perovskite research as a focus and has concentrated its second tranche of funding on that.
19. Oxford’s role as one of the two universities (with École Polytechnique Fédérale de Lausanne (EPFL)) that made the early advances in perovskite based solar cell research
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gave the UK a strong lead in this area. More recently there have been a growing number of groups involved but notably Sheffield (they have recent news on making perovskite devices by spray coating), Swansea (their Innovation and Knowledge Centre is working on manufacturing-related issues and applications of perovskites as a building coating), Cambridge taking a lead with light emission from the same materials, and several chemistry groups working on materials design and synthesis. With the initial start at Oxford and the Supergen investment the UK is probably in a good position internationally with perovskite research, but the materials fabrication is relatively easy and so many other groups are moving into the area (including some at Imperial).
The overall cost of solar PV systems
20. The cost and efficiency of solar PV modules are improving dramatically, but this means that the other parts of the system – the balance of plant – represent an increasing proportion of the total cost. Those components are well-known and so less susceptible to dramatic cost-reducing discoveries, but their costs are still likely to fall through learning-by-doing and a move to mass production. At an IEA workshop in February,78 Jenny Chase of Bloomberg New Energy Finance predicted that balance of plant costs for ground-mounted solar systems would fall 20% between 2013 and 2020 (and module costs would fall by 40%). The IEA Programme’s chairman, Stefan Nowak, presented data from Fraunhofer ISE showing that the balance of plant costs for rooftop systems in Germany had halved since 2006.
1 December 2014
78 http://www.iea.org/workshop/name-47388-en.html.
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Professor Richard Green and Dr Iain Staffell, Imperial College Business School – Written evidence (REI0056) Evidence on Wind Farm Performance Decline in the UK
1. Onshore wind farms in the UK have aged at about the same rate as other kinds of power station. The average wind farm has an annual load factor of about 28% when first commissioned, which declines by about 0.4 percentage points per year. After 15 years, the load factor would have fallen to 23%. This ageing does not appear to have made developers replace their farms early. Forty out of the first forty-five wind farms commissioned in the UK were still operating at this age; four had been repowered. Taking this deterioration into account raises the levelised cost of electricity by around 9% over a 24-year lifespan, discounting at 10 per cent a year. This is a summary of the peer-reviewed paper “How does wind farm performance decline with age?” published in Renewable Energy, vol. 65, pp 775-786, which is available to download from http://tinyurl.com/wind-decline.
Measuring the decline in wind farm output with age
2. All machines suffer a decline in performance as they age, but there were no plausible estimates of how wind farms might age in the public domain when we began our work in January 2013. Government-sponsored reports on the cost of generating electricity include ageing effects for other technologies, but assume that wind turbines do not age. The aim of our research was to estimate the effect of varying wind speeds on the output of each of the UK’s wind farms in order to reveal the underlying pattern of how output has changed over time.
3. Our wind speed data came from NASA, which publishes the MERRA database, giving estimated wind speeds for every hour on a grid of points across the globe. We used the grid surrounding each of the UK’s onshore wind farms to estimate the wind speed at the location and height of each farm’s turbines. We used the power curve for the specific model of turbine (which shows how much electricity it produces for a given wind speed) to estimate each farm’s power output in each hour from 2001 to 2013. We had to scale those estimates to account for effects such as rough terrain upwind reducing the wind speed at the farm, or the fact that turbines downwind from others will receive less energy. We tested our technique by estimating wind speeds at the sites of UK weather stations and checking them against observations, and comparing our estimated farm outputs with those recorded by the National Grid, which are available for farms in Scotland and offshore (but not in England, Northern Ireland or Wales).
4. We took up to ten years of actual monthly output data from each of the UK’s
onshore wind farms from Ofgem’s Renewables Register. The diamonds in Figure 1 show the monthly load factors for the Burradale 2 wind farm in Scotland, as an example. We calculated the weather-corrected load factor for each month (shown by the solid line) by subtracting the variations in our simulated load factors (from the
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NASA data) from these observations. This represents our best estimate of what Burradale 2 would have produced each month if it had received ‘average’ weather conditions. We have independent evidence that this farm was undergoing significant maintenance during the two periods with low weather corrected load factors (circled). The dotted line shows the trend in output over the entire period (including the maintenance periods) of just over -0.1 percentage points per year.
Figure 1: Actual and Weather-corrected Load Factors for Burradale 2 Wind Farm in Scotland.
5. We repeated this calculation for all the onshore wind farms in the UK. The trends are shown in Figure 2 for all the farms for which we had at least five years of data (i.e. those commissioned in 2007 or before). The vertical axis shows the date at which each farm was commissioned. The horizontal axis shows whether the trend change in output is negative (giving the ageing we would expect) or positive (as a small number of farms improved over their early years if initial commissioning problems took a long time to fix). Each circle represents our best estimate of the trend rate at which a particular farm has aged – the horizontal lines represent the standard deviation of this estimate. The size of the circle is proportional to the capacity of the farm, and it can be seen that the newer farms are generally larger than older ones. The central solid line shows how the average trend in ageing varies with the commissioning date of the farm, while those on either side give a band of plus or minus one standard deviation.
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Mo
re m
od
ern
fa
rms
More rapid decline
A few farms
increased output
over their first few
years (this is not
likely to continue)
Modern farms
appear to be
declining a little
slower than older
ones, but more
data is needed to
confirm this
Most farms lose
between 0 and 0.8
points of capacity
factor per year, and
this is seen across
hundreds of UK
onshore farms
Annual change in capacity factor (weather corrected)
Figure 2: Estimated rates of ageing for onshore wind farms in the UK
6. The average decline rate is 0.4 percentage points of load factor per year – this is
equivalent to 1.6% of the average farm’s output. The average onshore wind farm in the UK has a load factor of 28% at age 1, and this will fall to 23% by age 15. There are some signs that the newer wind farms are ageing less rapidly, for our central line is closer to the vertical axis at the top, but the error band around it is wide enough for all cohorts of farms to be ageing at the same rate, on average. Other methods to estimate the rate of output decline were tested in the paper, all of which gave numbers in the range of 1.4 to 1.8% per year.
Implications of this study
7. Our estimates of ageing are in line with those for other kinds of machinery. We are
unable to say whether the decline in output is due to mechanical components becoming less efficient after wear and tear, the blade surfaces becoming damaged and less aerodynamic, more time spent awaiting maintenance or some other cause. Assuming that ageing does not accelerate in the last few years of a turbine’s life, most wind farms should expect to operate for the 25 years typically assumed when they were planned. Most of the farms that have been decommissioned early have been repowered with larger turbines, and it is the opportunity to increase capacity, rather than the decline in the existing farm’s performance, that may have motivated the closure.
8. The ageing effects we have measured imply that the farm will produce 12.5% less
output over its lifetime than if there was no ageing at all. The cost per unit of electricity will increase by less than this, however, as the worst losses occur in the
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future. With an interest rate of 10 per cent, this would add 9 per cent to the wind farm’s levelised cost of energy – a noticeable increase, albeit one that is smaller than the difference between using a good and a bad site.
Why we undertook the study
9. The Renewable Energy Foundation published a study in 2012 that claimed the
“normalised load factor for UK onshore wind farms declines from a peak of about 24% at age 1 to 15% at age 10 and 11% at age 15.” A corollary was that “few wind farms will operate for more than 12–15 years.” This seemed implausible, given that the actual average load factor of UK onshore wind farms was 24.4% at age 10 and 23.3% at age 15.
10. A wind farm that is ageing rapidly could produce a nearly constant output if the wind was growing continually stronger, but it is easy to check that this is not the case using the wind speed index published by the UK government. The Foundation had used a technique (regression with dummy variables to represent (1) each farm, (2) each month’s average wind conditions, and (3) each age in whole years) that should have produced accurate results on average. However, given the large number of interacting dummy variables, it was vulnerable to particular combinations of data points that could lead it to produce extreme and unrealistic results. The Foundation’s results were internally consistent: each farm was producing much less output as it aged; the newer farms were on worse sites than early ones (on average); but because the wind was assumed by their model to get stronger over the last decade, the average output from the fleet remained high.
11. The Foundation’s results cannot be dismissed on purely statistical grounds, and even using a nationwide wind index might be misleading. We therefore undertook a detailed study of the actual wind conditions at each wind farm in the UK to infer the farm-by-farm rates of ageing described above. They are very different from those presented by the Foundation, but our results are consistent with the rates of decline seen in similar kinds of machinery and reported by some other researchers on wind ageing (including Professor David Mackay FRS). They are now being incorporated into some of DECC’s energy modelling work.
28 January 2015
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Dr Robert Gross, Imperial College London, Rupert Darwall and the Renewable Energy Foundation – Oral evidence (QQ 167-175)
Evidence Session No. 14 Heard in Public Questions 167 - 175
TUESDAY 13 JANUARY 2015
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Hilton of Eggardon Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Baroness Sharp of Guildford Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston
_________________________
Examination of Witnesses
Dr Robert Gross, Reader in Energy Policy and Technology, Imperial College London, Rupert Darwall, Author of REFORM publication How to Run a Country: Energy Policy and the Return of the State, and Dr John Constable, Director, Renewable Energy Foundation
Q167 The Chairman: Good morning. Welcome to this meeting of the Select Committee. We are grateful to our three witnesses for providing oral evidence to us today as we are coming to the conclusion of our inquiry into electricity resilience. We are being broadcast, so I will ask you first for the record to introduce yourselves, and if any of you want to make a short opening statement, do please feel free to do so. Perhaps we could start with Dr Robert Gross.
Dr Robert Gross: Good morning. Thanks very much for the opportunity to be here. Very briefly, I am an academic. I run a research centre at Imperial College. I am one of the directors of the UK Energy Research Centre. Among my research interests is the production of reports based upon systematic reviews—meta-analysis—of the available evidence. I have
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led reviews on the costs of intermittency, and what we think we know about the costs of technologies in the future and why we often get that wrong. I have also been a specialist adviser to the Select Committee on Energy and Climate Change, looking at its scrutiny of the draft legislation for EMR—electricity market reform. I have also spent a lot of my career looking at innovation, and looking at the outline questions that I have been sent by the clerk I imagine that is why I am here.
Rupert Darwall: My name is Rupert Darwall. I produced a policy analysis and review of the evolution of electricity market policy for REFORM late last year, and I am the author of a book on global warming.
In my opening statement I would like to offer your Committee four thoughts, if I may. The first is that the question of the desirability of decarbonisation as a policy objective is separate from the means of achieving that objective and the specific means that you are examining: the policy of supporting renewables.
The second is that if you subsidise high-fixed-cost, zero-marginal-cost intermittent electricity generation, you will end up destroying the market and incentives to invest in the capacity to keep the lights on when the wind is not blowing and the sun is not shining. That outcome was wholly predictable but wholly unanticipated by policymakers, at least in the White Papers and various public policy papers.
The third is that as a result the Government have been forced to take back control of electricity generation. We have therefore ended up with a structurally unsound hybrid of state control and private ownership. We incur the higher costs of private finance but we do not get the benefits of market allocation and capital.
The fourth—and this in reality is a fundamental choice that policymakers shy away from—is that you can have the market, you can have renewables, but you cannot have both.
Dr John Constable: Thank you very much for the invitation to give evidence. I am John Constable. I am director of the data and analysis publishing charity, the Renewable Energy Foundation, and we have long been concerned—indeed, since our creation in 2004—with the implications for system security and the cost-effectiveness of an overly rapid adoption of uncontrollably variable renewables. Indeed, in 2008 we published a major analysis, written with the well known energy analyst Hugh Sharman, in which we predicted the current generation capacity difficulties and their implications for system security and consumers, for many of the reasons which Mr Darwall has referred to. If that sounds rather like, “We told you so”, I am afraid it is meant to.
Q168 The Chairman: Thank you very much. I am conscious that some of our questions are going to be rather general and the temptation to wax at length is going to be great, but I hope that we can keep it fairly short and sharp so that we can cover as much of the ground as possible. Having said that, I must ask a fairly general question to begin with, which is of course that the coalition Government, early in their term of office, adopted EMR—electricity market reform—which some would say has brought back large-scale government intervention, which, of course, was previously reduced by the privatisation some years ago. Do you think that the present EMR policies strike the right balance between a market-led approach and government intervention? Who would like to start?
Rupert Darwall: My answer to that is no. There is in effect no balance to be struck. On your characterisation of EMR, I think the Government themselves characterised it as the
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Government taking control of the electricity-generating sector, and they do not foresee a return to the market until 2028. Indeed, they believe that there will be three five-year plans to get us back to a market. I think there is a fundamental problem with the Government specifying the type of generating technology that there should be, and in particular subsidising a form of generation that, for reasons that we can go into, destroys the ability of investors of dispatchable capacity to have any form of predictable returns on their investment. So there is no balance to be struck. The choice is: do you have a market or do you have renewables?
The Chairman: Dr Gross, would you like come in on this?
Dr Robert Gross: I kind of agree and disagree. EMR is interventionist, and it seeks to bring about a transformation of the energy system. If we were not concerned about climate change, we would not have EMR. The system that we had before EMR was introduced was doing okay in terms of the efficient use of fossil-fuel power stations. We had a problem in that we were prematurely closing a bunch of coal-fired power stations and the market was not responding quickly enough to that problem, but we did not need EMR in its entirety to solve that problem, and I do not think that we needed EMR in order to meet our 2020 targets for renewables either, because we already had the renewables obligation, which could have been extended and made to work to meet the 2020 targets for renewables. So I think we should be clear that one of the reasons why we have EMR is that the Government decided that they did not just want to build renewables, they also wanted to build new nuclear power stations, and they did not have an environment that made that possible for investors because those nuclear power stations were exposed to too much wholesale power price risk and volatility over the long term, so the Government created many of the structures around EMR in order to allow those nuclear power stations to come into existence. We can discuss whether or not that was a desirable thing to do, but I think we have to be very clear that if we want to transform the energy system to radically decarbonise it in a relatively short space of time, we cannot do that based on the system that we have now. We can discuss whether EMR is a kind of halfway house and whether it was a kind of reregulation by stealth. If you look at the history of policy ideas in this country, you can see that it kind of is. We kind of could not admit in 2008 or 2009 that what we really wanted to do was tell the energy sector what was required of it, so we ended up with this halfway house. The question, pragmatically, having spent several years getting on with this legislation in place, is whether it can be made to work, not whether we can tear it up and start again as if we had never done any of that. I think we probably could if we got the political commitment that is required in order to make that happen. I will stop there.
The Chairman: Would Dr Constable like to add anything?
Dr John Constable: Yes, I certainly would. The key character of EMR is given away by a single term in some of the EMR documentation. The first, “administrative pricing”, indicates a very significant intervention into the electricity market, and if you doubt that, Mr Davey, Secretary of State, wrote in the Guardian quite recently actually using those words; he describes it as a very significant intervention in the system. He was, in fact, rebutting an editorial calling for even more. Why did the Government choose to extend their interventions? As Dr Gross quite correctly says, the Renewables Obligation was already there. Well, this is distressed policy correction. Having so damaged the market with distortions such as the Obligation, they found themselves in the absurd position of having to provide counter-subsidies to encourage investment in other technologies. This is a perfectly
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foreseeable sort of outcome from the market distortion which Mr Darwall has already referred to.
Q169 Viscount Ridley: The focus of our inquiry is energy resilience. Is what Dr Gross was saying correct: that decarbonisation comes at the expense of resilience, that it cannot not come at the expense of resilience, that we can do something to improve resilience after that but we are bound to make resilience worse? This slightly goes to the question of intermittency, which we will come to later. Are decarbonisation and resilience opposites? Are they orthogonal?
Dr Robert Gross: I can see no particular reason why they are. I can see that we will have a conversation—
Viscount Ridley: Because dispatchable power is not there when the sun does not shine or the wind does not blow.
Dr Robert Gross: I think it depends on the mix of technologies that you put into the market. If you want to radically decarbonise the energy system, you need to have CCS, nuclear, or renewables, or some combination thereof. You need to have a system that is different and in some respects more difficult than just having flexible fossil-fired power stations that you can ramp up and down in order to meet demand, but I do not think that it is in any way inevitable—and there has been an awful lot of work internationally—that you end up with a system that is less resilient as a result. If fossil fuel prices are low, you probably end up with a system that is more costly as a result, but I do not think it means that it is less resilient.
Lord Dixon-Smith: Chairman, I apologise to the Committee if I am wasting its time, but I want to ask a question that should have been asked six or seven years ago. Is the fundamental policy of reducing our carbon emissions by 2% a year—because we have to reduce it by 80% over 40 years—appropriate? My own view has always been that rushing into green technologies when we do not know anything about the competitive position of doing so is exceedingly rash, and I think we have been driven by this policy when it might have been more sensible simply to look at getting the generating capacity that we need at the best cost and taking a bit more time to learn about how we could actually decarbonise the system. I think we are driving through on the basis of a fundamental policy flaw.
Rupert Darwall: Could I respond to that? If you look at the history, the fateful date in this episode was the spring 2007 European Council at which Tony Blair committed Britain to the most demanding renewables target in the EU. Before that, the Government’s policy was, if you like, coherent and rational: to rely principally on the EU’s emissions trading scheme. That was a market-based approach that would have enabled competing technologies to demonstrate and reveal which were the most efficient at generating electricity at the lowest possible cost. But after that point, once the renewables target had been established the rest of it fell away and there has been this huge push into driving a technology that has very destructive impacts on other generators.
Q170 Lord Broers: Dr Gross, from what I heard you say, EMR was introduced mainly to find a means of financing nuclear. I had naively thought that it was to cope with the intermittency of weather-based renewables.
Dr Robert Gross: I think you need to look at the different components of EMR. I think the most significant shift that the EMR package of measures introduces—we can talk about the
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capacity mechanism, which I believe we are going to come back to—is long-run, fixed-price contracts for all forms of low-carbon generation. In the case of nuclear that means that you can enter into a fixed-price contract for, I think, 40 years. I do not think we should see EMR as being introduced in order to make up for the limitations and shortcomings of weather-based renewables; I do not think that was its principal requirement. Lots of electricity jurisdictions around the world have capacity mechanisms. We can have a more or less academic conversation about whether or not we can allow the market to function in the absence of a capacity mechanism, whether scarcity and so on will signal the need to build new power stations and whether policymakers wish to rely on that or whether that in itself imposes price spikes and so on, and whether security is an externality, and so on, but I disagree that the most significant component of the EMR package is the capacity mechanism. I think that the most significant component of it is the contracts for difference.
Lord Hennessy of Nympsfield: I was intrigued by a passage in the mini-biography of you that we have. You argue that, “Just as engineering R&D may be measured in terms of patents or improvements to products, so policy research may be measured through improvements to policy and policy thinking”. Many of our witnesses—and Mr Darwall already today—have been pretty critical about successive Governments’ ability when it comes to energy White Papers and thinking ahead. It is as if Whitehall and successive Ministers lack the divine spark ever to get a grip on this problem. Energy supply is a perpetual problem for every Government. It is one of the first requirements of the state, yet many witnesses, and I think you this morning too, have suggested that there may be something inherent in the difficulties of energy policy review that means that all this looks so unsatisfactory in retrospect—or is that an unkind judgment on past Governments?
Dr Robert Gross: At the risk perhaps of straying too far into the philosophical, I do think that there is a collective gestalt—a collective mindset—of the day. If you look at when EMR was first considered, there was Project Discover, which Ofgem ran, and then a subsequent Green Paper, that began to worry about these issues. I think many of us thought at the time that we would probably introduce something like a low-carbon obligation that was a bit like the renewables obligation with tradable certificates but extended to include nuclear and CCS. But internationally at that time we saw that feed-in tariffs—fixed-price contracts for renewables—had been extremely effective at bringing renewables to market around the world, and that they were delivering renewables more cheaply because they derisked more effectively for various categories of prospective investor than the rather complicated system that we had in the renewables obligation. At the same time, we wanted to create an incentive scheme for nuclear that did not look quite like a subsidy so that we could try to get it through the state-aid scrutiny process.
I am not apologising on behalf of the Government for all these things, I am just observing, as someone who has been involved as an academic and as an adviser to Governments and Select Committees looking at how these events unfolded, that one can kind of see how we have ended up where we are. The biggest difficulty with where we are in practical terms is that we have tried to derisk by creating technocratic derisking in the form of the contracts for difference, but we do not have the political support across the piece. In particular, we do not appear to have the support of the Treasury that allows that legislation if you like to be given a chance to work, because if we are trying to do something over a 15-year period out to 2030 but we have no clarity whatever about what we are going to be doing after 2021, and if investors are already perceiving this to be contested within the Government’s own
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ranks, you cannot expect the cost of borrowed capital to come down. Cock-up rather than conspiracy would be my analysis.
The Chairman: I will ask Lord Rees to ask his question next, and then I will ask Lord Broers to move us on.
Lord Rees of Ludlow: A question really for Mr Darwell. You extolled in your pamphlet the move away from state towards the market post-1990. How do you feel that has worked in the nuclear industry, because as I see it we have lost a great capability in the nuclear industry, and if we have nuclear power stations in the future they will be state-owned by the French state or the Chinese state, which seems perhaps to be an unfortunate outcome of post-1990 policies? I would like to ask you to comment on that.
Rupert Darwall: I think, Lord Rees, that you are absolutely correct in saying that the market did not want to finance nuclear power, and that is simply because the process of privatisation revealed the horrible economic record of Britain’s civil nuclear programme, which was a financial disaster. It is very difficult to find anywhere around the world where the market has financed nuclear power without any state support. That is an example. If you want nuclear power, in some way or another you will want the state. I personally think that privatisation was a huge benefit in revealing the very poor economics of nuclear power.
Q171 Lord Broers: Are sufficient steps being taken by the government regulator and National Grid to ensure the resilience of the electricity system? Are National Grid’s new balancing services likely to be sufficient to balance supply and demand over the next two winters? Will the capacity market be effective at balancing supply and demand in the medium term? Is there is a risk that too much capacity will be supported and the cost to consumers too high? Finally, does the capacity market provide sufficient promotion for measures such as demand-side response and interconnectors? If not, how could this be addressed? A lot of questions, I am afraid.
The Chairman: I do not know whether Dr Constable would like to address the question.
Dr John Constable: I will take up the last question about the demand-side response. I have noticed a worrying tendency to regard demand-side response as a long-term planning measure. That is, I think, imprudent. Demand-side response is really a last resort. It is a short-term, operational measure, and the consequences of allowing it to drive the market are likely to be unfortunate. A thought experiment may help: suppose you are a capital investor thinking of deploying capital in the United Kingdom. You obviously have options elsewhere—you have the option of building your factory in an economy where demand is allowed to command supply. On the other hand you might put it in the UK where apparently supply is going to be allowed to regulate your demand. Where are you going to put your money? Even if you are rewarded with some kind of generous payments under a demand-side response system, you may well wish to remain in the driving seat. Liberty is not perhaps so easily obtained that you should want to surrender it for mere cash payments.
With regard to interconnectors, I think the case for them is greatly overstated. We published extensive work concerning the performance of the interconnections between Denmark and the European network: the UCTE system. The work was conducted for us by Paul-Frederik Bach, who was planning director for Eltra and therefore responsible for managing wind power. His conclusions were that although interconnectors were very valuable economically—trading was generally a very good idea—the role of interconnection in
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supporting wind could be greatly overstated and that you should not take the full capacities of the interconnectors at face value. When the system is under stress, the interconnection will tend to be reduced, for very good reasons. I do not think that is now particularly controversial; it is referred to in a recent study for DECC by Mott Macdonald—a document called Technical Measures for the Mitigation of Electricity Imbalance Risk, which I am not sure is published, although it is certainly in circulation. Mr Henney, I think, mentioned it in evidence to this Committee. If you do not have it, I would be very happy to submit it, as I happen to have a copy and I think it would be of use to you. It refers at some length to the limits for interconnection, and I think it would be valuable for you to read it.
Lord Broers: The interconnection capacity is quite small anyway, is it not?
Dr John Constable: Relatively small.
Lord Broers: Do you think we should increase that capacity, or is it just not going to be a winner anyway?
Dr John Constable: I would be very much in favour of further interconnection for electricity trading, but I would not expect it to be particularly valuable in managing the uncontrolled variability of large renewable fleets in the UK. It would have to be justified on other grounds.
Lord Broers: So it is very unlikely to be very windy in Denmark when it is calm here.
Dr John Constable: Work, again conducted by us in 2008 and now by others, looking at the synchronisation of weather systems over northern Europe shows that similar weather conditions tend to prevail over very large geographical areas.
The Chairman: Would either Dr Gross or Mr Darwall like to refer to National Grid’s new balancing services and tell us your confidence in that delivery?
Dr Robert Gross: I am very happy to do so. To be frank, I do not think there is an awful lot else that we can do in the short term. We absolutely have to overcome a situation where margins are tight and at the same time plants are mothballed. That cannot possibly be in the public interest. I think we need to be clear about the source of the problem, which is that we have prematurely closed a bunch of perfectly serviceable old coal-fired power stations for reasons to do with environmental concerns other than climate change, and that either the ability of the market to provide new capacity quickly enough or the ability of policymakers to anticipate this problem and put new policy measures to oblige the market to provide capacity quickly enough failed to deliver. We are in the situation that we are in, and to the best of my judgment National Grid is doing what it can to make sure that we do not have power cuts—blackouts, to use a tabloid phrase—over the next couple of years before new generation begins to come on stream and the situation begins to ease. This is not a problem caused by renewables; it is a problem caused by EMR to the extent to which when you say that you might have to have a capacity mechanism you damn well have to have a capacity mechanism. It becomes a self-fulfilling policy, so it is a policy problem in that regard—“We said we were going to have one, but we did not get one quickly enough”.
It does make me cross when I read press reports that we are returning to energy rationing. Energy geeks for as long as I can remember have been fascinated by the idea of smart demand-side response and so on, because generally speaking the demand side does not do anything in the electricity market. Economists like the idea of markets where all the participants are able to participate fully in the activities of the market, and I see no difficulty or problem at all in an undertaking of any form, a company of whatever form, that signs an
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interruptable contract, gets cheaper power as a result, and probably will not get its supplies interrupted but is prepared to do so in extremis if called upon to do so—and a whole range of other cleverer things that we might be able to do on the demand side in the future, but they are not relevant to this particular conversation.
Q172 Lord Wade of Chorlton: Obviously I understand your concerns and criticisms, and I have a lot of sympathy with them, to put it bluntly. But what policy should we adopt to try to improve the situation? What proposals can you make as an alternative to what we have? How do we get out of it?
Dr Robert Gross: I do not think we can do anything other than what we are doing over the next two years, because too much time delay is involved in bringing new capacity to market. I think it is extremely unlikely that we will have power cuts. National Grid may need to call upon some of the interruptable services and do other things in order to ensure that we get through this period of tight margins. Beyond that, you had some very eloquent evidence from David Newbery that I read in the transcript about the functionality or otherwise of the capacity mechanism. I very much think that we can debate the longer term, the 2020s, decarbonisation, nuclear versus CCS, and all the rest of it, but I really do think that having just got these policies into place and with all this apparatus around the capacity mechanism, we need to give that a chance to work to make sure that the system stays reliable.
Viscount Ridley: At the risk of sowing a little discord between you, I understood Dr Robert Gross to say that the fact that we are mothballing gas stations at a time when capacity is getting tight, as it were, is not a problem that is caused by renewables, but is not the issue what Mr Darwall said: that if I am the owner of a gas power station, I have to take into account the fact that I am up against a competitor with zero marginal cost, so I cannot be guaranteed to be able to have the customer for my electricity all the time and I therefore have to switch off when the wind blows, which destroys the economics of my entire operation? Is that not the issue, where renewables and the capacity mechanism come together?
Rupert Darwall: I respectfully disagree with Dr Gross on this. If you look at the EMR policy papers, Chris Hume used to say that the big problem was the “missing money” problem. The “missing money” problem is caused by intermittent renewables, so the EMR was set out to address that problem. In the US, one of the effects of renewables, and you have identified this problem, has been that a nuclear power station is going to be closed prematurely. If you believe in decarbonisation, that has to be the most senseless outcome you can imagine. Nuclear power stations have very, very high sunk costs at the beginning and the end of their lives. When they run they cost virtually nothing, but the impact of renewables has been to put a huge question mark over nuclear power stations in the United States.
If you step back and look at the bigger issue, Dr Gross has talked about the political risk as if it is being generated from within government and from within the Treasury. The political risk is what you read in the newspapers, and that is voters complaining about higher electricity prices and political parties in a democracy competing for votes. You have one political party saying, “We are going to freeze energy prices. We are going to regulate energy prices”, and all that is a big sign to investors of the growing political risk of investing in the UK generating market. It is that aspect of political risk that is a fundamental problem with EMR in this halfway house, in that the Government are saying what technologies they want investors to put their money into and at the same time are asking investors to manage and price political
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risk which the Government’s policies are creating. In my view, that is fundamentally unsustainable.
Dr Robert Gross: I would just like to make a couple of points in response to that. The first is that the “missing money” problem has been discussed in energy economics over an extended period of time, and long before we had even the slightest sense that we might be able to make the progress with renewables that we have made.
Viscount Ridley: Could I have a quick definition of the “missing money” problem?
Dr Robert Gross: The “missing money” problem is that prices will not spike high enough for you to make the scarcity rents that you need in order to invest in a new asset. That is the heart of it. I am very happy to give supplementary evidence on that if that would be helpful.
Can I just also make the point that if we were having the conservation about Germany, we could legitimately talk about the current capacity of renewables having significant impacts on the profitability of conventional generating stations? We are nowhere near that position in the UK at the current time.
Viscount Ridley: We are hoping to get there.
Dr Robert Gross: We are hoping to get there, but we should not misconstrue the problems that we face over the next couple of years. Those problems result primarily from policy and investment decisions that were made in the mid to late 2000s for a number of reasons, such as failing to act swiftly enough to make up for the shortfall in the closure of the coal-fired power stations. I do not think those decisions and judgments were being made because of EMR, because EMR was not even a twinkle in the eye, and that we were going to move to this world of such deep penetrations of renewables that you would not be able to recover the investments that you made in a gas-fired power station.
Dr John Constable: Can I comment on the “missing money” problem? The coal stations closed because of the Large Combustion Plant Directive, but capacity failed to come forward because the future market, even under the renewables obligation, was likely to be much smaller and much more volatile. Therefore the load factor for an investor in a gas turbine was going to be very low, it was going to be very difficult for them to recover their fixed cost, and there was an insufficiently strong price signal for them to want to build combined cycle gas turbines. That was true under the Renewables Obligation, quite regardless of the EMR. Indeed in some respects, as I have already said, the EMR is an attempt to restore some kind of price signal for investors in firm capacity. It has the additional benefit from the Treasury’s point of view, of course, of putting some kind of limit on the cost of the scheme after 2020; the Renewables Obligation was clearly running away.
Lord Willis of Knaresborough: I often have a discussion about missing money with my wife, so this is a new look at it. I would like to take you back to Lord Broers’ early question about the new balancing services which the Government and the suppliers have brought in for the next two years to ensure that we have a balanced system. Are we simply adding more complications to the system by these new devices? Would we not do better to try to increase the margins well above 4% or 6% to somewhere around 10%, as Dieter Helm suggested in his evidence to us?
Dr Robert Gross: If we allowed the generation market to make more profit rather than it not making very much profit, and then the utilities—
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Lord Willis of Knaresborough: We are aiming to have a balance at around 4% of supply over demand. If we increased that to around 10%, as Dieter Helm suggested, we would not need the sorts of balancing services that have been brought in for the next couple of years.
Dr Robert Gross: I think that would be a rather risky approach. National Grid ultimately, as the system operator, has the responsibility to take actions in the balancing market and ultimately to use various direct contracts that it has with generators, and to a lesser extent with the demand side, to ensure that demand meets supply instantaneously at every moment. I have come from an engineering-based university and perhaps I am biased in this regard, but it seems to me that if you are worried that the public interest will not be served by the electricity market because of various failings, whether policy or market—and whose fault they are we can discuss—extending the ability of the system operator to contract for new services and in extremis to require companies to make capacity available is a better way of providing a safety net in difficult times than hoping that if we allow them to make more profit, that might happen by itself.
Dr John Constable: I think you are actually asking whether derogations would be offered to plant that is currently being retired under the Large Combustion Plant Directive rather than about the economics of it, were you not?
Lord Willis of Knaresborough: Yes.
Dr John Constable: That would be very embarrassing, to say the least, and perhaps not feasible. You have to remember that this plant has been expecting retire, so it has been run down. Whether it could be granted a prolonged lifetime is open to question, but it would certainly require some kind of breach of the large combustion plant directive, and I suspect that would be very controversial.
Q173 Lord Peston: I would like to take us on to costs and that sort of thing, but before I ask the specific things that I have in mind, I must say that I very much agree with Rupert Darwall that the industrial structure that we now have in this sector is totally irrational, and with all due respect to Dr Gross I do not think there is the slightest chance that it would enable us to get an optimal outcome, however you define “optimal”. Let me also add that taking a sceptical view of decarbonisation was never an available option in our country, or indeed in most other countries, to any of the political parties at all, so we have to go ahead on the basis of a positive response to decarbonisation, and therefore we have to look at what it costs us. I take it that we all agree with that. The economics of then looking at the costs at the theoretical level is incredibly easy: you do it by discounted cash flow. I take it that you agree that that is how we have to take these decisions. The problem is how you calculate the costs in practice rather than in theory. In particular, surely a great deal of the problem revolves around what discount rate we use in comparing the different flows of capital and current costs and returns. Do you have a view on the correct discount rate? As you know, there is a massive economic literature now right across the spectrum for the answer that it ought to be nought right through to the answer that it should be a very high number. What is your view?
Rupert Darwall: You have put your finger on a very important question. Essentially, the Government are specifying what generating technologies should be invested in. The public sector has a cost of capital that is quite low. The private sector has a higher cost of capital because it is at risk, and when we look at electricity and higher electricity prices they layer
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political risk on top of that. So in my view an important thing to look at is the cost of capital of various arrangements. In the last days of the last Labour Government—I think it was in March 2010—there was a joint DECC-HMT assessment that looked at which structure for the industry would generate the lowest cost of capital. As part of the justification for the EMR the Coalition Government looked at the switch from a renewables obligation to CfDs and they got some economists to look at the gain from the reduction in the cost of capital. That reduction in the cost of capital under the EMR is a fraction of what you would get if the state paid for what it mandated. So my prime beef with the current arrangements is that if the Government want the generating sector to look at a particular way, if they want renewables, the best thing to do is to get out their chequebook and pay for it. That is the lowest-cost outcome for the economy as a whole.
Lord Peston: Sorry, I do not understand that. I mean, the cost should not depend on who is financing it. The cost is a real economic phenomenon.
Rupert Darwall: The supply of finance will depend on who is providing the finance. If you are using state finance, it will cost less than if you are using—
Lord Peston: Yes, but I thought that economists had long since abandoned that position. Of course the state can borrow more cheaply than the private sector, but that does not mean that the state should therefore finance something. I thought that we had abandoned that in economics donkey’s years ago.
Rupert Darwall: It is because the private sector’s higher cost of capital is offset by greater private sector capital allocation efficiency, and we have lost the benefit of the market allocating capital—we have the state allocating capital. In theory, the cost of capital is the asset, but in this particular example it has been aggravated because you have the whole question of political risk, and private investors have to price in political risk for all the reasons that Dr Gross has talked about and that we read in the newspapers. Investors will be concerned that the policy arrangements underpinning their returns will not be continued because they result in too high prices, at some point the policy framework will change and in a sense their returns will be expropriated. So they have to price in a higher cost of capital. That is just a fact of life.
Dr Robert Gross: I actually agree with an awful lot of what Rupert is saying about this. What we might have done had we approached this rather differently right from the beginning is say, “Well, a nuclear power station or a large offshore wind farm is an asset”. It is a big like the National Grid, and we allow the National Grid to operate as a monopoly with a regulated return on investment, which means that it is attractive to certain categories of investor risk categorisation, which generally means that like most regulated asset base utilities it can borrow money more cheaply than the traditionally competitive market for fossil-fueled power stations. I remember Dieter Helm writing a very interesting paper—since he has been mentioned—suggesting that we might have done just that. It is a step short of doing it through public finance but it might be able to realise much lower costs of capital, and because these things are so capital-intensive, as you rightly say the discount rate is of immense importance to this. We have not gone down that particular road; we have gone for a kind of halfway house, which, as I have said, seemed as though it ought to work at the time, and it was what was acceptable to the mindset, if you like, of the Treasury economist at the time. If it turns out to be an unmitigated disaster and we are not accessing cheaper
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money, then obviously we need to think again. But we have scarcely got this through the statute books; it has had very little time to—
Lord Peston: Can we finish off on this? Are we able to answer the simplest and most naive question—namely, what does a typical onshore wind farm cost in capital terms and what does a typical nuclear power station cost? Going back to my younger days as a junior economist in the Treasury, we always knew that a nuclear power station would cost at least twice what the advocates claimed—a typical Treasury view, I agree. In fact, it usually turned out to be four times what the advocates wanted.
The Chairman: The attempt at privatisation proved that, did it not?
Lord Peston: Do we have any hard data, so that those of us outside could work on it and take a view?
Dr Robert Gross: I would be very happy to send you data on capital and costs—
Lord Peston: So you definitely have that and you would live and die by it.
Dr Robert Gross: I would not live and die by it, although I would live and die by it on the costs of building wind farms. There is a very large global market for wind farms, so we have a good idea how much it costs to build a wind farm. We have a much less good idea about how much it would cost to build a nuclear power station in this country. Frankly, we really do not know how much it will cost to do carbon capture and storage—CCS—which I am rather enthusiastic about and think we should do more on.
Lord Peston: Do we have any idea about costs for building a tidal barrier?
Dr Robert Gross: We have estimates of how much it would cost.
Rupert Darwall: Can I just follow up on that? You have put your finger on an incredibly important deficiency in EMR, in my view, which is the very poor accountability. A great volume of spending is being financed by consumers and not by the Treasury, so there is very little data—we do not know what that spending is procuring. I find that a very big worry, because in this halfway house—this ill defined no man’s land between the private and public sectors—we do not know as much about what is going on as we would if it were within the public sector, where there is traditional public sector accountability.
Viscount Ridley: We know the cost of a wind farm today, but do we know whether it is going to come down in future? We have heard very divergent views in the inquiry between people who think that the cost of renewables, particularly solar, is going to come down and those who have said that the cost of wind might not come down so much. What are your views on that?
Dr Robert Gross: I have done an awful lot of work on this. What we can say is that the cost of onshore wind came down steadily through the 1990s and early 2000s and then plateaued. There is some evidence that there will be a return to cost reduction in onshore wind but probably nothing like the scale of cost reduction that we saw in the early period, when we were realising economies of scale and so on. It is also important to be clear that movements in markets—movements in the competitive position of how many manufacturers there are and all these kinds of things—can influence prices just as much as learning affects an innovation and getting better at technologies. If I had to make a projection, I would say that we could expect a return to modest cost reduction in onshore wind. I think there is the
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potential for a considerable and dramatic cost reduction in offshore wind, but not if we go charging after it and do it all wrong, which is what we have been doing up till now.
Lord Broers: I have another quick follow-up to that. None of these wind farms has been running for very long. Are you equally confident about the maintenance costs of these things for 20 years?
Dr Robert Gross: We have been operating wind farms since the early 1990s.
Lord Broers: Yes, but a lot of those are extremely unreliable. You can drive by them and see at least one-third of the turbines stopped. Are you sure about the maintenance costs?
Dr Robert Gross: I am not a wind farm operations and maintenance engineer, but I know that we are able to make an advanced gas turbine with all the stresses and all the issues that that involves and we are able to make incredibly reliable motor car engines, so I cannot think of any conceivable reason why great big companies like Siemens, GE and the rest of them that make wind turbines would not be able to make them operate reliably.
Lord Broers: But for a while they could not. It was only Bosch and some other German companies that came in about five or six years ago with gear boxes that they would guarantee for 20 years. These gear boxes are transmitting power unlike any other gear box in the world and they have to be placed on top of 300-foot towers, so if they go wrong it is not easy to crane them out and replace them.
The Chairman: Let us park that one, because I am not sure that we are going to get an answer on the long-term maintenance costs. If there is any further evidence that anyone can send us on that, we would be grateful.
Q174 Lord O'Neill of Clackmannan: Part of what we are concerned about in resilience terms is intermittency. What would you regard as the options for overcoming this intermittency? The ones that we have already had posited are flexible generation, interconnection, storage and demand-side response. Would you take much comfort from these options as alternatives or as anchors for resilience?
Rupert Darwall: I cannot give you a technical answer, but what I can suggest on renewables is that, while we have been discussing the maintenance costs of wind farms and whether they have been falling, of course there is a whole dimension that that debate tends to miss out, which are the costs that they impose on the rest of the system—the grid costs—and on other forms of generation. That is essentially what we are discussing this morning. One solution to that problem is for wind generation to internalise the costs that it imposes on the rest of the system. You do that in two ways. First, you charge for the extra grid infrastructure that wind farms cause to be built. Secondly, in terms of the costs on the rest of the system, you go back to having the wholesale pool that we had in the early days of privatisation, where you bid to supply a certain quantum of power at a particular time of day. That would force—
Lord O'Neill of Clackmannan: Sorry, but, with respect, you seem to be obsessed with markets. There are engineering dimensions here. I suggested storage as something that might be a means of doing this. Do you have a specific answer on matters of a technical character relating to what we are trying to come to—a technical answer to the problem, which is resilience?
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Rupert Darwall: I can suggest how resilience could be improved by having a pool whereby if you know that you have to and are committed to—
Lord O'Neill of Clackmannan: Sorry, but I have asked you about storage specifically. Could you give us a clear answer: do you think that storage is one of the means of undermining the bad effects of intermittency and is it worth the candle in terms of the cost?
Rupert Darwall: The most efficient form of storage is hydro power. If there are enough valleys that you want to flood with more hydro schemes, that would be the best way to go.
Dr John Constable: Can I chip in on this one? Technically, storage can obviously solve the problems. The question is whether it is affordable. If you look at renewable energy flows from wind, wind offers you only one large charge-discharge cycle from which you can recover your capital. That is not sufficient, given the cost of current storage options, so you tend to retreat up the curve and find that the storage options are going to be dealing with relatively small fluctuations in wind, rather than large ones. So it is an economic question rather than a technical one.
Dr Robert Gross: Could I offer something on this as well? One thing that we need to be very clear about is the scale of the problem that intermittency imposes at what kind of penetration of wind and how well studied and how well understood this issue already is. When I led a review of this back in 2006, I think that we found 104 peer-reviewed or system-operator, National Grid-type studies into the costs and impacts of intermittency. Last night, when preparing for this, I read a couple of excellent reports from the International Energy Agency, reviewing both the engineering principles and the issues across countries, as experience is building, and some of the market adaptation and changes. I really would hope that the Committee, through the clerk and your special adviser, pays attention to and is aware of some of the excellent work that is already being done in this area and is not swayed by the kind of headline-grabbing think tank that is secretly a lobby group and has commissioned a retired engineer to come up with some oversimplifications and some very high numbers for the costs and impacts of intermittency. We have the grid upgrading costed by the electricity network and supply group at about £9 billion. If you annualise that and smear it out across consumers, and take into account the additional system balancing services that are likely to be required to manage wind and the impact on capacity and so on, and if you work through all that, with about 20% or so penetration of renewables on the system you come to a small number of perhaps 1p to 2p per kilowatt hour. The problems begin to arise when we start to look at very ambitious post-2030 combinations of very deep penetrations of renewables, with perhaps lots of solar on the distribution network and perhaps new nuclear stations as well.
To answer your question in a rather long-winded way, when one looks at those kinds of scenario, doing that without storage or intercontinental interconnection and those kinds of thing looks almost impossible. Storage then becomes terrifically important. But we must not exaggerate the scale of the problem that we are facing at the moment in an engineering and technical sense.
Dr John Constable: 1p to 2p per kilowatt hour might sound small, but you must remember that the UK consumes 330 terawatt hours per year, so it is not a small number when you multiply it.
Dr Robert Gross: All the numbers in the energy system are large.
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Dr John Constable: The extra costs are in fact very substantial.
Q175 Lord Rees of Ludlow: We heard evidence from Dieter Helm, whose views you probably know. He felt that we should not subsidise present renewables but should go for gas in the short term and invest more in R&D into improved renewables. Do you agree with his general line? Can you perhaps say a bit more about your favoured future options regarding renewables and storage?
Rupert Darwall: I think that the problem with the push for renewables—and this comes back to Lord Hennessy’s point—is that because renewables were the favoured technology, data and analysis that did not really support the adoption and aggressive rollout of renewables tended to be pushed back. I fundamentally believe that the right policy framework is where markets can discover costs and those costs are internalised rather than socialised. Going back to my earlier point, if you had a pool, which the opposition party is promoting, it would force clarity of costing intermittency. It would give intermittent renewables investors incentives to develop storage technologies. It would give them incentives to team up with dispatchable technologies and to invest in dispatchable power. The costs then become more visible to the people promoting particular forms of technology.
Dr Robert Gross: While I do not disagree with much of that, I do disagree with the way in which what Dieter said has been phrased. I completely disagree with the notion that we could abandon deployment of low-carbon technologies now and put money into R&D instead and that some sort of magic solution will pop out at some point in the future. It is like believing in the R&D fairy. It flies in the face of everything that we know about technological change and it completely fails to engage with the amount of time that it takes to roll out large amounts of new infrastructure. This is an urgent problem, which we need to get on with. We will obviously discover better ways of doing things in 30 years’ time. To the extent that we can, we need to try to strike the right balance. I have read the transcript and I think that Dieter was actually questioning whether we are striking the right balance. That is a very legitimate question, which we could explore more if we were not about to run out of time. To be absolutely clear, if you do not deploy anything, you do not get anywhere. You cannot build an offshore wind farm in the lab, you cannot build a PV factory in the lab and you cannot build a CCS pipeline in the lab. There are no magic solutions hiding—at least, not ones that will make a difference in the next 20 years or so. It is very worth while spending money investing in R&D in storage, for example. That could be hugely important and game changing. All sorts of things will come along that will improve things as we go along, but we should not just think that that is all that we need to do and that we can just wait for them to make a difference.
The Chairman: We have come to the end of this session, but does Dr Constable want to add anything as a last word?
Dr John Constable: Professor Helm’s suggestions are extremely constructive as a means for trying to preserve something of the climate policy from consumer rebellion. We are looking at extremely high consumer costs for very long periods of time. It seems extremely likely to me that the climate change agenda will suffer as a consequence. That might be very unfortunate. There is a very good reason for having a climate policy, that is an insurance policy, but the premium has to be proportionate to the risk. Currently the costs are too high and Professor Helm’s suggestion seems to me to be a way of shifting to a more reasonably priced insurance policy and thus keeping the public on board, which might be rather
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sensible. Do not forget that subsidies for renewables will be close on £8 billion a year in 2020. With additional systems costs, the figure will be well over £10 billion per year for decades. These are extremely high additional costs on the system and are very likely to produce consumer rebellion.
The Chairman: This session could have continued much longer and, indeed, other Members were trying to catch my eye at the end. I say sorry to them that we have had to close this session now. Thank you for what has been a varied session, with the three of you not entirely in agreement, but all the better for that, because it has given us a lot of further information, which we will need to consider carefully. We have been urged by you to make sure that we are not swayed unduly. We will certainly be looking, as always, at the evidence base. If you feel that there is further evidence that you need to direct our way, do by all means send it to the clerk. Thank you very much indeed for a very informative morning.
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Professor Michael Grubb, University College London and Professor David Newbery, Cambridge University – Written evidence (REI0026) Written evidence to be found under Professor David Newbery
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Professor Dieter Helm CBE, University of Oxford – Oral evidence (QQ 44-52)
Evidence Session No. 4 Heard in Public Questions 44 - 52
TUESDAY 28 OCTOBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Hilton of Eggardon Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston ________________
Examination of Witness
Professor Dieter Helm CBE, University of Oxford.
Q44 The Chairman: Welcome, Professor Helm, we are grateful to you for joining us. We are being recorded and webcast, so perhaps you would like to just give your name for the record. If you wish to make an opening statement in any shape or form, please do so.
Professor Helm: Thank you, chairman. My name is Professor Dieter Helm. I am professor of energy policy at the University of Oxford. I will just make one very short opening remark and then answer as many of your questions as I possibly can. It is a quite extraordinary state of affairs for a major industrialised economy to find itself even debating whether there is a possibility that the margins may not be sufficient in electricity to guarantee supply, particularly in a context in which electricity is increasingly important to the economy, and where information technology and so on depend absolutely crucially on a continuous supply. That context is not just unfortunate from a security supply point of view. If it was achieving carbon objectives and producing low prices, there might be some consolation, but the wholesale price in Britain is twice that of northern Europe. On the CO2 front, we have been switching from gas to burn as much coal as possible, and our emissions are actually rising on
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a production basis while, of course, on a carbon consumption basis, which is the basis that matters for decarbonisation, they continue to rise. For a major industrial economy to fail on one of the three objectives is a serious problem but to fail on security, on competitiveness and price and on decarbonisation is a sad state of affairs. It is even sadder in the context in which the problem is not, fundamentally, particularly difficult—it is ultimately about having enough power stations and enough wires to supply to the needs of the population. It is a problem that has been with us for a century. Many other countries solve these problems. It is, as I say, rather sad that we have got to this particular point.
The Chairman: Thank you. We will listen with interest to some of the further answers you are going to give us.
Lord O’Neill of Clackmannan: I suppose I should start my question, Professor Helm, with “nevertheless”. You have mentioned en passant the question of resilience and we have had repeated assurances—although I am not sure if they are reassuring—from National Grid as to, let us say, the next two years suggesting that we, with a wee bit of luck, will get through. I am paraphrasing that. Perhaps you could give us your slightly more detailed concerns about how resilient you think the next two years of British power supplies will be and how accurate you feel the National Grid assessment is?
Professor Helm: The first point to make is that there is always a price at which supply will equal demand.
Lord O’Neill of Clackmannan: Provided there is sufficient generating capacity.
Professor Helm: No, if there is deficient capacity in the sense that it looks like we need more, if the price goes high enough, then supply will equal demand. So when you talk about resilience, it is not just about physical resilience. It is physical resilience at a price that is reasonable for people to pay. For example, supposing the capacity margin went to nought, the price would rocket up as it did in California and people would turn themselves off. That is how it works. So when you talk about resilience it is very important to separate out whether you physically think that there may be something wrong with the wires or whether you think that the price at which you wish to supply the power from the power stations is one that you want people to bear.
If you look at the current situation, of course there is enough capacity to meet demand if you do what is necessary to do that. To the best of my knowledge of National Grid in particular, but also from experience across much of the economy, people are pretty good in a crisis. There is enough kit lying around that could be brought back in time. I always use the analogy of the Spitfires: if enemy aircraft are coming over the top and you have to get the planes in the air, if you really have to do it, then you do it and it can be achieved. It is amazing what you can get out of existing kit if you need to. In the context here we have interconnectors and we have, bizarrely, modern mothballed gas stations while we are running very old—extremely old in some cases—polluting coal stations at almost base load on our system. So the kit is there. If the will is there to do it—I think the expertise and capacity of the grid is up to it—they will manage to make supply equal demand. The question is how much higher the price will go as a result and how long Britain can carry on having such high wholesale prices with all the consequences there are for British industry and consumers.
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Q45 Lord Broers: What novel risks to resilience do you think will emerge over the medium term and how can such risks be mitigated?
Professor Helm: In many of these areas it is extremely tempting to predict the future: to know how it is going to work out and then plan, or have some kind of scheme, to deal with each and every thing you predict. The important thing to say about the medium term, and about any policy designed to address energy resilience as well as the other objectives, is that it is uncertain and that you should plan for the uncertainty as part of your policy.
If we look across the frame, the first effect is already with us, which is that the commodity super-cycle is over: gas prices in Europe this year have halved, coal prices are falling and the oil price is down to $80. As we witnessed in the 1980s, the preparedness for the consequences of the way in which the system operates when prices change substantially is not what it might be. People have not thought through the consequences yet of fossil fuel abundance and potentially—I say potentially—low prices. We have a policy which the Secretary of State repeatedly reminds us is based on the idea that gas prices are rising and volatile. Well, they are falling and we do not want to protect customers from having the benefit of the volatile falling prices in their bills. It would be a bit like going to the petrol station and saying, “Thank you very much for having a policy that protects me from getting a lower petrol price today. I am glad I do not have volatility of paying 127 rather than 135 per litre”.
The first big story is about whether your system is robust against very different fossil fuel price projections, including ones very different from the Government’s, and about how the system will operate. The second thing is about the networks. The question about the networks is really dependent in large measure on what is going to happen with intermittent renewable supplies. If we are to build lots and lots more offshore and onshore wind farms, then you need a much more robust and resilient grid than if you are going to build some substantive base load power stations. The resilience issues for having sets of nuclear power stations, or gas stations, are completely different from the resilience issues of having intermittent power round the system. Should we worry, in resilience, about fuel supplies? No, I do not think so. The world is awash with gas. Unconventional gas is popping up all over the place. Qatar no longer has to export its gas to America. America is 25% of the world economy and is no longer importing. There are plenty of supplies around: lots more being discovered in the Mediterranean areas, plenty of supplies in North Africa and new fields being found in the North Sea and so on.
The one medium-term “risk” that I would pay much less attention to—but clearly the Government thinks they should pay much more attention to—is whether or not we will get enough supplies of fossil fuels. We have enough fossil fuels in the world to fry the planet many times over. If only we had to worry about security of supply on fossil fuels, maybe we might do something about climate change, but that is not one of our problems.
Lord Broers: You are suggesting that, before we tackle this particular question, there are things that we do in the UK that are making things more expensive inherently, such as inefficiencies. Your analogy about the petrol station is a good one. With petrol, we seem to have a ratchet that only goes one way. It is coming down a bit now but never as much as perhaps it should.
Professor Helm: The prices and efficiencies in the system you get depend on how good you are at achieving the objectives you set yourself. If the objectives are to decarbonise, then
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you might think we would choose the cheapest way of decarbonising. Well, in the last few years, what we have done is switch from gas to coal on a large scale—Germany has done even more, by the way, switching to having 45% of its electricity generated from coal—whereas if you really quickly want to reduce emissions you switch from coal to gas. Gas has half the emissions of coal. It is not the long-term solution but that is what you do. We have done the opposite.
Then, thinking about the technologies that might actually address climate change, it is very hard to see how offshore wind, for example, could do that. It adds an enormous amount of cost. It is three times the wholesale price, which is twice the north European wholesale price at the moment, and it is very questionable how much the costs come down. That is before the network costs are added in as well. If you want to end up with expensive electricity, and not make much progress towards your carbon objective, my suggestion is to switch from gas to coal and build lots of offshore wind farms. But if you actually want to address your agenda, then you want to do something different.
On security of supply, if you want a secure supply system but if you add capacity to your system that reduces the security of supply because it is intermittent, you have a price to pay. You can chose to pay that price but you cannot be surprised at the outcome in terms of the cost to the grid if that is what you set yourself doing. In one sense, this is about the simplicity of energy policy, but what makes it very difficult is that you have to be very clear of what precisely what you want to do. Once you have sorted out the questions you want an answer to, such as reducing the carbon production and consumption in this country and increasing the security of supply, then certain consequences follow. But what we have is a host of particular interventions loosely associated with some broad almost slogans as to what the objectives are, without specifying what those objectives are and what the relationship between the policy and the objectives is. That is where I would start, but that is why it is so expensive.
Lord Broers: So government policy is quite wrong in all of this?
Professor Helm: We have a policy that has been unfolding for some time. I call it the Miliband-Huhne-Davey policy, because it is very consistent through that period, and it is based ultimately on some assumptions that I do not think have any part in energy policy. Those assumptions are, first, that fossil fuel prices are going to go up. Early on in the Miliband-Huhne period, talk was of doubling the fossil fuel prices. If you think that is true, know that to be a fact or are pretty certain it is going to happen—if you are all-seeing—then of course you can design a correct energy policy because by 2020 the current renewables will all be economic. The poor Americans will be stuck with all this expensive fossil fuel and we, the Brits, will have relatively cheaper power. For instance, you could imagine petrochemical industries not leaving Europe and going to the United States but trying to go to Aberdeen to get near some of the relatively cheaper offshore wind, if you know that the prices are going to double. That is an outcome of the market, not a policy assumption to make. Your bet could turn out to be correct, but if it turns out to be dramatically wrong—fossil fuel prices are falling, not rising, for oil, gas and coal—then you are going to have lots of technologies that are going to be “out of the market” for some considerable period to come. We will have to subsidise those technologies right through the 2020s and beyond, unless—from a policy perspective—the prices suddenly rocket up and make these economic. In terms of this knowledge that politicians have about the winners, we have been there so
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many times before in the history of energy policy. It usually turns out badly and it has done this time.
Q46 Viscount Ridley: There is another aspect of energy security, which is the political risk of getting energy from other countries. You have made the point that gas is probably not suffering a very high risk of that at the moment because there are so many parts of the world we could get it from. At the moment about 40% of the coal we burn in this country comes from Russia. Are we not much more exposed to political risk in coal than in gas?
Professor Helm: I had rather hoped that autarky went out of fashion as a trade policy sometime in the 17th or 18th century. If you look at the markets in oil, gas and coal globally, it is perfectly sensible to have a view about short-term interruptions—there can be fires at terminals, there can be short-term political issues et cetera—and to have stocks. That is why we have a strategic oil stock and I have always been in favour of some form of strategic gas stock. On the coal side it is less obvious, although we did discover during the miners’ strike that you can stock a hell of a lot of coal at power stations.
To just take fuel, is there any serious chance that we are going to face an oil embargo any time soon, like we did during the Yom Kippur War in the 1970s? No. There are more plentiful sources of oil supply around the world; it is a fungible market. As for gas, the world is awash with gas. People do not seem to have fully taken on board the fact that the United States—nearly 25% of the world economy—has stopped importing gas. All that stuff built in Qatar and elsewhere was built with a large US market in mind, and that supply is now on the world market. Indeed, we have so much gas that the world could absorb the shutdown of the entire Japanese nuclear industry and prices would not go up very much. So there is plenty of gas, and there is plenty of gas from lots of sources. The Norwegians have been complaining for years about how the Europeans are not buying enough gas and using enough gas from their source of supply. There is plenty of LNG around the place and, as I say, if markets were worried about gas supply, how do you explain the fact that the gas price has fallen by half in Europe since the Russians occupied Ukraine?
On coal, it is all over the place—disastrously from a climate change perspective. In this commodity super-cycle the big mining companies have been developing new mines and new resources on an enormous scale. Even the Germans have been doing it by opening new lignite coal mines to burn the coal in their so-called green Energiewende system. So there is plenty of coal all over the place and no risk about supply. That is the one risk I would not spend my time worrying about right now. Should we have some security of supply in form of storage and stocks? Yes, that is sensible, but it is not a problem that is likely tomorrow morning to wake us up in the dark.
Q47 Lord Wade of Chorlton: I agree with your analysis completely, I think you are hitting the nail on the head. But I want to put the following point to you. If you had a straightforward supply and demand, in other words the cost was the cost of the raw materials and the cost of delivery, and the customer could then choose the best price, that would be fine; but suddenly we have these green issues thrown into the pot. There is not just one green issue, because we have created this structure of decarbonisation that has so many different elements in it and so many different groups wanting to do it this way or that way. The Government have ended up trying to please not just the customer but all these varied green groups so that they all vote for the Government that is in power at the time.
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How do we solve that? To me, that is the basic issue of the whole shooting match. If this is what we have to do—and I am not even persuaded that it is—then what is the simple route for resolving what the right and proper single-entity way is to deal with carbon that everybody, including the Government, could agree on? Then we can find the most competitive and sensible way to do it.
Professor Helm: If I have indicated that markets can solve these problems on their own, that is not my intention. There are clearly market failures here that will not be taken into account by competitive firms or companies, and that requires intervention. Our objectives drive that intervention. So if you want security of supply, you have to fix the quantity and make sure there is a capacity margin. That is a clear intervention. If you want to decarbonise, you have to make sure that investment and plant operation follows a decarbonisation path. Those are the two things you need to do.
So the question is what the simplest and most efficient route, and therefore the lowest-cost route, is for doing that. What I have proposed for some time is that there should indeed be capacity auctions, but just capacity auctions not three or four different sorts of capacity auctions for each different kind of technology. You simply say, “This is the quantity that is required” and you auction it on a rolling basis. Within that framework, you want that new capacity that comes on the system to be going in the direction of decarbonisation. There are two ways of doing that. The simplest and most straightforward way is just to have a carbon price: let the carbon price go to whatever levels necessary to achieve the target and then people will bid capacity that takes that into account into the capacity market.
Of course, politicians do not like that because we might have to confront people with the pollution they cause in their consumption every day of items that embed carbon. So instead you pay £150 per megawatt hour for offshore wind or £160 plus the network cost. If you add that together that is a phenomenally high carbon price. You pay a much lower carbon price in respect of the coal, which is where you would want the carbon price to bear. So it is not that we do not have carbon prices, it is just that politicians would rather them be embedded in picking particular winners and supporting particular technologies, so you do not see that is the carbon price.
If that is what you want to do and if you are not prepared to have a carbon price to confront people with the consequences of their actions, then a second best is to say, having had your capacity auction, “We need a gigawatt in 2025 bid, anyone can bid”. You then have a second stage of the auction and say, “I have looked at our carbon budget programme as put forward by the climate change committee and, you know what, actually we will have a second bid, which has to be purely low carbon this time”. So you have a two stage auction if you are not prepared to have a carbon price. QED.
There are of course many lobbies out there that will be offended by that idea; after all they are getting the subsidies. This is a huge rent collecting activity for lobby groups, vested interest et cetera, each trying to get the Government to pick what they think is the particular winner that they represent. They are very good at it, and so they should be. It is like the National Farmers Union campaigning for farming subsidies. These groups are very professional in the way they go about it. We have learnt that picking winners is such a bad idea because the Government are very easily captured by vested interests. This is a capture process in which you need a political scientist to explain how you end up with the result you
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get. It is much more consistent with capture than it is with any rational economic supply curve of the technologies.
Q48 Lord Peston: Dieter, you will lose your licence to practise economics if you do not follow the normal economics line of telling us a tale of woe about fossil fuels. Going back to Stanley Jevons and so on, economists specialise in saying it is all going to run out and our successors are going to all be much poorer et cetera. In your article in the Oxford Review, you emphasise the fact that we are awash with fossil fuels and ought to recognise that—which, let me add, I am sure is completely right. That means that you are not telling us a tale of woe, but I just warn you that there are others around who will insist on a tale of woe. I now know why that is, from your point that there is money in telling a story that it is all going to be terrible.
I want to look at the capacity market and ask what your view is of that. But before that, when I first started in this field of the economics of choice of investment in generating stations, the key variable that we always looked at, quite erroneously as it turned out, was the discount rate. You have not mentioned the discount rate. Do you think, in terms of the decision-making process, that it really does not matter what the discount rate is, because we are talking about building capacity that will last a very long time?
Professor Helm: No, it is extremely important. On your point about peak oil et cetera, I would hate to disappoint you by not saying something gloomy but I—
Lord Peston: No, you do not disappoint me, I am delighted, but I am unusual in that.
Professor Helm: But I just want to be clear. The fact is that we have, as I said earlier, enough fossil fuels to fry this planet many times over.
Lord Peston: It is like a widow’s cruse: the more we use the more we find.
Professor Helm: There are good reasons why reserves keep going up rather than going down. But from a climate change point of view it would be easy and helpful from a particular perspective if peak oil was true and we were running out of the stuff, and we had no option but to decarbonise because otherwise the lights were really going to go out. Unfortunately, that is not true. We have abundant fossil fuels and we are not running out. These technologies that need very high fossil fuel prices to be economic are going to find themselves probably—although not certainly—out of the market for a long time to come in the same way as some of the oil and gas producers from Russia to the Middle East are going to find their budgets pretty well strapped compared with the plans for what they would have spent the money on had they had it.
On the discount rate, the heart of the capacity market issue relies on two separate things. First, it is that you want the electricity system to have more capacity than the mean expected demand. That is the point. You want excess capacity. That is why we are talking about 4% being inadequate. I am not sure who knows the right answer, as it will never turn out that way, but 15% to 20% seems to me a much better place to be from an economic perspective of the economy as a whole risk. So you have to give people money to deliver something that will depress the market price. Putting it the other way around, one of the reasons why the price is high and likely to rise with these tight margins is that there is no excess capacity in the market.
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Secondly, people who invest in this market need to think about the potentially stranded costs among their sunk and fixed costs. If you build something for the long term, how do you know you are going to still make money further out? The answer is that you do not, and if technical change is fantastically fast—which I think it is and we might come on to that in a moment; by 2030 we may be talking about completely different kinds of technologies—then the question is whether you really want to commit yourself to the long term. From society’s point of view, if you face stranded assets sooner rather than later, you would want to use a higher discount rate rather than a lower discount rate.
This comes to the heart of picking winners. There is not much discussion about what the time dimension is of the winners the Government think they are picking. So if you ask, “What do we need now?”, the answer is that technology is as given today and what we need is, to be blunt, some pretty substantive power stations brought on to the system pretty fast. There is only one technology that could do that quite quickly, which is gas. You can get a gas station up in a matter of years, and there is virtually nothing else base load you can get up that quickly. It is just a fact of life. But further out, do you really want to commit beyond 2030 when next-generation solar, electric cars and all sorts of other things may be on the system? That is more difficult.
Should we as a society commit to the sunk cost? If we offer long-term capacity contracts over a long period of time, we are socialising the potential stranded cost that is there. That is not a bad thing to do, and it is not wrong for people who build long-term technologies to expect us to do that if they want us to deliver those, but it is an open question about whether it is a good idea. That goes to the heart of the discount rate, which I think is extremely important in the capacity auctions.
Q49 Lord Peston: Could you just expand on another thing? The whole point about technological advance is that it is unpredictable. If you could predict the new technology, then essentially it would not be the new technology, it would be already to hand. How are we to handle that?
Professor Helm: That is a very important point and it is too easy to go to the two-corner solution, which is, “We are uncertain, therefore, we should not do anything” or, “We are so certain we know it is A, B, C, D and E”. If you look at what you might do in this space—this is about R&D essentially—there are certain strands of technology where you do not know which one is going to be a winner but you know a potentially quite fruitful strand for which research money ought to be devoted.
I will just sketch them out, because you want to know what ones are relevant to the problem you face. It is pretty clear that none of the existing generation technologies are going to make much difference to climate change. Professor Dave MacKay’s numbers illustrate this, but you do not have enough shallow water and land to cover it with enough windmills to make any significant difference to global warming at all. Whatever its other purposes, it is not going to do that. Current rooftop solar is not going to do that either. In nuclear, we are going to lose 100 reactors worldwide before we gain 100 reactors, so it is not going to expand its market share for quite a long time to come, even if there are new builds in lots of places in the world. There are also lots of questions about nuclear.
So you are left with solar, geothermal, next-generation nuclear and gravity—hydro in some form or other. If you pick those off, you would be foolish not to think that the solar territory
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is quite pregnant with possibilities. I say pregnant with possibilities—we do not know the answer but we do know about new materials like graphene, we know of new developments around solar film and we know things about opening up the light spectrum look promising. Remember you are spending £100 billion on subsidies for other stuff. You do not have £1 billion for subsidising these sorts of areas, so £200 million on solar or getting beyond the £60-something million we devoted to commercialising graphene might be a much better option than spending billions on offshore wind farms. The second area is storage. Energy storage seems pregnant with lots of possibilities and it is very important because the electrification of transport gives us a possibility of leaving the oil in the ground eventually and not needing it. There are huge diverging strands of research in storage, but we might want to pursue that. Then finally, there is IT. If you look at many of our infrastructures, it is as if IT was never invented. We have not worked out how to optimise railway systems. If we go down the great western line, much of it is not digitalised in a sensible fashion. If you look in the electricity world, we are passive on demand not active. We are passive with regard to systems, not active. This must be a fruitful area to start thinking about smart meters and so on in that framework.
So those are some of the areas you might go in. As I say, we are spending £60 million or maybe £80 million on commercialising graphene, which is this amazing material, but we have billions to spend on offshore wind. I am only suggesting just a marginal rebalance but the efficiency gain, and the potential for British industry and for climate change, lie in those territories, not in endlessly building more offshore wind farms and expensive technologies like that, which cannot solve climate change.
The Chairman: You have given us three areas where it might be profitable to look in the future. Some would call these picking winners: solar, storage and IT.
Professor Helm: I said areas, not particular technologies.
The Chairman: Are the Government not entitled to do the same?
Professor Helm: The Government are perfectly entitled to—I would thoroughly encourage them—to support R&D. That is not the same as giving a particular feed-in tariff to a particular chosen technology. I have been extremely careful in my answer, first, to be clear that it is not about two extremes and, secondly, to be very clear there is a distinction between spending money on research and spending money on particular technologies. I talked about areas of research and I would like to point out the cost-benefit difference. We are talking about relatively small sums of money with potentially substantive gains, as opposed to talking about very large sums of money with very little gain.
It seems to me that no civilised Government would not want to have an R&D programme, and if you are going to have an R&D programme, there is a sense that you have to spend money in some areas rather than others. I have only highlighted three general areas within which an enormous amount of research is going on, which looks to be pretty exciting. But the truth about R&D is most of it is wasted. That is what R&D is about: pursuing dead ends, things going wrong et cetera. But we are not committed to the sunk cost, for decades to come, of the fact we may have spent £60 million on commercialising a particular aspect of graphene that does not work out. These are distinct problems and it is easy for those who support particular subsidies for particular technologies to say, “Well, since you are in favour of R&D you must be in favour of picking winners, therefore, why can we not pick these particular winners?”. The difference again is the winners have large economic rents attached
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to them. Of course there are rents attached to research areas—there is money for research and people do want to get it—but it is on a different scale and it is a different kind of problem to the one that is in the FITs and the current capacity contracts.
Q50 Lord Willis of Knaresborough: I wonder if I could just bring you back to one small point. This particular inquiry is into the resilience of electricity infrastructure and we, to be fair to politicians, have to make some short-term decisions in terms of resilience. The short-term decision that has been made is that you need roughly 4% capacity over demand, for which there is a particular price to pay. Our witnesses so far have said that in the short term they have questioned whether that can go forward with the mechanisms that National Grid has put in place and whether that is sustainable. But in terms of cost, you mentioned a resilience of somewhere in the region of 15% to 20%. Is the cost of that, of pouring money into mothballed equipment, not going to be huge in terms of the cost on the consumer? I just did not follow your logic in that.
Professor Helm: If you run a system at a 4% or 2% margin the price will be higher. Everyone will pay a higher electricity price because the price needed to bring the market into equilibrium is higher, because the stuff is scarce. If you have a capacity margin that is higher, the sort that any reasonable electricity system around the world would think of as being sensible given the risks, the prices will be lower. That is why people will not produce or not bring excess capacity onto a system without an incentive because it deflates the market price. So you have to do a quite careful calculation before you jump to the conclusion that increasing the capacity margin leads to an increase in consumer prices. The best way to have high and volatile consumer prices is not to have a capacity margin.
Lord Willis of Knaresborough: Why would the Government not do that? They have an election next year and there is a huge attraction in offering better prices to customers.
Professor Helm: It is not my fault that this problem has been going on for a decade and Governments have done nothing about it. They have only now got around to starting capacity auctions seriously for the period beyond 2018 and have almost an emergency on their hands—perhaps not really an emergency, but a very tight situation. That is not my fault. That is the position they have got into. If you really want to think through how complacent politicians have been, remember that the British economy is now about 20% to 25% smaller than you would reasonably have predicted it was going to be now back in about 2005 or 2006. Most people would not have predicted that the economy would shrink 6% and grow at 0% for a period of time. They planned it to grow at 2% to 3%. If the British economy was, at the end of the last investment cycle—you have to go back into the middle of the last decade to plan out investment—25% larger now, you would not be discussing resilience you would be discussing a serious full-on crisis. We got lucky in one respect. We have crashed the economy—not deliberately, but the consequence of that is to buy us 10 years of time, in which we have not addressed the problem. It is not difficult.
You do need a capacity market; you do need that component. Some people have been arguing for a very long time to put that in place. It is better late than never but you cannot get that to solve the problem for the next two years. What you have to do for the next two years is rely on National Grid to do a very professional job and bring the capacity that is mothballed and sitting around on to the system so that can be used. There is enough capacity and this can be done, and to the best of my knowledge National Grid is extremely professional at doing that. There will be a cost and a price: if you do things in a hurry short
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term, you are bound to have additional costs. But this does not detract from the point that you want never to be in this situation again. You want to get to a situation where you have a comfortable margin. Any reasonable, large-scale economy like the British economy, with its reliance on electricity, is vastly better off in a world in which it is quite content and has a bit of fat in its capacity margin so it does not have to worry about these kind of problems, which play down on the aggregate price in the market. To run around saying, “Thank God we only have 4%, at least we are not spending money on mothballed power stations” is not a state of affairs that we want to get into. It is not hard. Is the right answer 15%? I do not know. It is certainly north of 10% and it is probably less than 20%. But who knows whether the British economy will be 25% bigger in 10 years’ time, the same size or smaller. So the error is very big. You just want to be risk averse, because it is asymmetric risk. If you are too short and the prices rise, everyone suffers. If you have too much, the cost is socialised across the whole economy, and who cares too much about that. It would be nice to be in that situation.
Q51 Lord Rees of Ludlow: I want to go back to the issue of R&D. Clearly it needs to be greatly increased and I agree very much with your three areas. One would like to see R&D in the energy area worldwide come up closer to medical research in terms of level of expenditure. But the question is how we do this. It should be a global effort, when much of it is pretty competitive. What could we in the UK do to maximise the rate of increase in R&D? To what extent should we promote a national effort? To what extent could we do this through the international bodies? I wonder if you could say a bit about that.
Professor Helm: Climate change is a global problem and much of invention is a public good. Clearly, if someone in the world could come up with answers in these technological areas, we would all be better off because we would all benefit from less global warming.
In terms of how to do this, I am personally averse to Gosplans of R&D. You need to let quite a lot of flowers bloom. Graphene was discovered in Manchester; I think early aspects of 3D printing were discovered in Bath. It is not necessarily the case that you need some global Manhattan project to achieve this outcome but, on the other hand, if people are going to come up with next-generation solar, and solar films that can be applied, or if they are going to get forward in opening up the light spectrum and so on, shared endeavour is important.
I have been very modest in a sense of limiting my comments on this to say that in terms of importance R&D versus, say, offshore wind is to me a no-brainer. We have an enormous sum spent on something that cannot solve a problem—although it may have some uses in particular locations—and virtually nothing spent on something that we absolutely rely on. My starting point is that existing technologies cannot solve this problem. In terms of how to do the detail of that, that is way beyond my expertise and, with respect, you probably know vastly more about that than I do.
Lord Rees of Ludlow: But the one thing you do know is that a public good like this is undersupplied by the market, so the Government have to take some initiative. The question is what the UK Government could do, perhaps through international fora, to increase the level so that we get more quickly to these technologies that we all benefit from.
Professor Helm: I am normally averse to the idea that the solution to problems is public expenditure, but we could certainly spend quite a lot more on R&D and we could do that through our existing institutions by increasing the amount available to our core universities and so on to take these things forward. But also we could contribute to international R&D
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and there are lots of different ways of doing that. One is to encourage co-ordination between countries. Sometimes that is very difficult but, for example, R&D co-ordination between China and the UK will be increased by the development of the Hinkley plant and there are many other areas in solar and elsewhere where we might want to do that, for example with the United States. The answer many people try to advance here is that we need some kind of international R&D institution. There was the plan for the European MIT, there have been lots of statements about international new Manhattan projects. I am personally very sceptical about those and I think they take a long time to get going.
Lord Rees of Ludlow: Obviously one area where this has happened already is in fusion, which is long term. The ITER project is huge and many are ambivalent about that. But would you agree with me that if we are spending, say, $2 billion a year worldwide a year on fusion, and we calibrate things against that, we should be spending much larger sums worldwide on other areas of energy, although in those other areas there is no need to have a single grand project as there has been proved to be in fusion?
Professor Helm: If you follow and agree with the steps in my argument—that is a big if—the first step is the existing technologies cannot solve the problem. Therefore, you need new technologies.
Lord Rees of Ludlow: I think we agree with that.
Professor Helm: If you take the next step, which is to say that climate change is a really serious problem with potentially very high costs associated with it, then the cost benefit of devoting resources to those things that could help you mitigate and then solve that problem seems to me to be pretty overwhelming. What is the right answer? In R&D how would you know what the right exact amount of money to spend is? You would not. But what you do know is that if you take together all the contributions in the North Sea and the networks versus a few hundred million, absolutely maximum, is an order of magnitude mistake that provoked me to write a book about the subject some time ago. That is what needs to be addressed.
Lord Rees of Ludlow: Do you think the cutback in nuclear R&D is a mistake?
Professor Helm: It is not for an economist to go around and say, “You should spend a lot more on nuclear and a lot less in another area”. We are open to all the kind of lobby interests and so on in these areas. But if you accept that the R&D process is very wasteful, in the sense that most of it will not succeed, and you identify what kind of technologies you would need to have to crack the climate change problem in terms of these three dimensions of generation, storage, and the IT and active side of demand management, then you would want to spread your money across those areas. I think it should be a much bigger pot relative to spending on existing technologies and subsidising those. Experts like yourself will know much more about the details of the science; it is not for economists to opine on that, but there is a good argument from the evidence that you would want to encourage quite a lot of lines of inquiry rather than concentrate on just one or two.
Lord Rees of Ludlow: Yes, especially the three areas you mentioned.
Q52 Viscount Ridley: How important is energy density? In other words, in deciding what areas can and cannot solve the problem, I think you are saying that one of the big problems for wind is that it is a very low-density energy—1.5 watts per square metre or whatever it is. What we have done is move towards more and more dense energy systems. In agriculture it
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is called sustainable intensification, the idea that we use a smaller footprint to produce the same amount of energy. It is clear that fossil fuels have a high energy density, that nuclear has an even higher one and that things like wind and hydro are pretty low ones. In between, solar is the question mark, in terms of whether it can get to a high enough energy density to make a difference. Do you think that is an important metric or not?
Professor Helm: It is one of the metrics to take into account. What an economist would say is that you should get the prices right for the things you want and then the market can sort these things out. I have one slightly sceptical remark on that front. Supposing you were to have a technological breakthrough, as some people talk about in the solar space, and suppose it turned out to be really incredibly cheap to apply solar film to virtually anything on a very decentralised basis; supposing that was possible in a decade or two, then the decentralisation that would result in such a world—particularly if you had localised storage—would be such that density would not be a serious problem in the way it is if you have a centralised electricity grid system. This comes back to the central point I tried to stress: we do not know, but you have to at least have in your mind the possibility that the assumption that we have made, that we need a centralised large power-station-based system, may just not turn out to be the case, just like it may not turn out to be the case that the oil and gas price is going to double, as our previous Secretaries of State were so certain it would. So we do not know in that frame and, therefore, that is one consideration but not the only one. I have one final rider about trying to run main electricity systems, basically pretty centralised ones, off onshore and offshore wind. David MacKay’s book demonstrates wonderfully—and I am amazed that people in DECC either did not read it or understand it when he was chief scientific adviser—that it is sufficiently low density that it cannot provide a solution to the problem of climate change. That is why you have to move on. You can make wind turbines more effective, you can get much better at harvesting loads, but the fundamentals there point against it being a way of solving global warming and global climate change.
The Chairman: I understood that you were hoping to be able to leave us before 12.30 pm, you have just achieved that by two minute. I am sorry as I know we could have gone on a lot longer. There were indeed members of the Committee who were trying to catch my eye, and I apologise to them for not having been able to call them. Thank you for your robust and very clear evidence. I will read it again with great interest and of course you will, as you know, get a written record that you will be invited to correct for inaccuracies. Thank you very much for joining us today.
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Alex Henney, EEE Ltd79 – Written evidence (REI0015) The generation mess We have got in a position where our generation policies comprise:-
Building an expensive nuclear plant costing £16bn for 3200MW. According to Peter Atherton, utilities analyst at Liberum Capital, the project’s capital cost at £5m per MW makes it the world’s most expensive power station on a per MW basis (except for hydro schemes, where costs vary with terrain). He describes the agreement as ‘one of the worst ever signed by a British government.’ Atherton estimates that it will generate annual profits of up to £2bn (rising to £5bn by the end of the 35-year contract period) for generating 7 per cent of the UK’s electricity compared to the combined profits of all the power stations owned by the Big Six of only £2.1bn in 201280
Supporting residential solar panels in our gloomy climate with subsidies which make nuclear look cheap
Supporting expensive (£95/MWh) - and for offshore, very expensive (£155/MWh) – wind which costs respectively two and three times the current wholesale price of electricity. Furthermore, as I showed with empirical data from Ireland81, in a system such as ours with little hydro, wind farms do not achieve the mitigation of CO2 they claim on the tin. In Ireland the system operator publishes the CO2 emissions from the whole system every 15 minutes. When the large pumped storage system, which is used to balance the system by offsetting the variability of wind, was not functioning in 2011, the mitigation of CO2 reduced by 60%. There is report that Germany’s flagship Bard 1 offshore wind farm of 80x5MW turbines has so many technical problems and is costing so much that it may cast doubt on such scheme82s. To compound the folly of this policy much of the subsidy is going to Scandinavian and German companies, thus weakening our balance of payments situation
Throwing subsidies at wood chips from new cut trees in the US. In 2012 and 2013 Professor Searchinger of Princeton informed DECC that new cut wood chips actually
79 I was on the board of London Electricity 1981-84. My report “Privatise Power” published by the Centre for Policy Studies in February 1987 was the first to propose a competitive restructuring of the electric industry with a pool. After the election in June I was involved with Rt. Hon. Cecil Parkinson and officials in the early days of restructuring, and wrote a paper “The operation of a power market” which had an influence on the course of events. Subsequently I have advised on electric markets from Norway to New Zealand, and published “The British electricity industry 1990 – 2010: the rise and demise of competition”. 80 Sources: Liberum Capital (2013), ‘Flabbergasted – The Hinkley Point Contract’; Peter Atherton, ‘Why has Britain signed up for the world’s most expensive power station?’, The Spectator, 22 February 2014. 81 See an article I wrote with former CERN physicist Fred Udo “Wind – Whitehall’s pointless profligacy”, New Power, Issue 45, October 2012. 82 Blog NOT A LOT OF PEOPLE KNOW THAT, 13/9/14. Note that a year ago there were concerns about some Danish off-shore schemes, and there have been rumours about problems with one or two British schemes.
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increases CO2 emissions because of the loss of sequestration83. With its customary disinterest in evidence based policy (but it is strong on policy based evidence), DECC ignored this. But it did appear to take note when 60 US scientists wrote to Secretary Davey and Chief Scientist Professor Mackay on April 24 2014 stating “We, the undersigned scientists from across the US, are concerned about the rising use of wood sourced from Southern US forests as a fuel for electricity generating power plants in the UK and Europe and urge you to take swift action to develop and adopt sustainability criteria and carbon accounting requirements to ensure adequate protections for forests and the climate…Recent advances in science and accounting for pollution from different types of woody biomass have clarified that burning trees to produce electricity actually increases carbon emissions compared with fossil fuels for many decades and contributes to other air pollution problems”84
The unproven prospects of Carbon Capture and Sequestration (CCS). In 2003 the government said it would set up “an urgent implementation plan…to get a CCS project off the ground.” The government then launched a competition for a coal fired power station with post-combustion coal technology CCS. The competition for four plants took four years to complete. Eventually only one scheme (a retrofit of Longannet by Scottish Power) was left. In late 2011 DECC concluded that the scheme was too expensive, and said it would launch another competition for four projects including applications from gas fired stations. In December 2013 and February 2014 it signed Front End Engineering Design Contracts with two projects. The earliest any plant could be completed is well past 2020. The “urgency” of 2003 drags on! E.On in the Netherlands has perhaps the most favourable project of installing a post-combustion system of 250MW on a new coal plant it is building at Maasvlakte near to Rotterdam, and pumping the CO2 into a depleted off-shore gas field 20kms away. Although the project has €180m from the EU and €150m from the Dutch government, E.On is reluctant to put up the remaining funds. After a decade Vattenfall is reported as stopping research on CCS. As in as number of other areas we have Davey’s ill-informed boast that “we are leading the world” - but no one else is following!
In considering the Energy Market Reform project (EMR) it is important to appreciate that it is not a “reform”, but a replacement of the market. Under EMR, the electricity sector will be subject to no less than three consecutive five-year plans (2014-2018; 2019-2013; and 2024-2028). The government85:-
83 Sound Principles and an Important Inconsistency in the 2012 UK Bionenergy Strategy, http://www.rspb.org.uk/Images/Searchinger_comments_on_bioenergy_strategy_SEPT_2012_tcm9-329780.pdf. Letter from Tim Searchinger to Bernard Bulkin of DECC, 8/2/13. The Economic Benefits of the UK’s Nuclear Supply Chain Capabilities, Oxford Economics, A Report Commissioned for DECC, https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/168017/bis-13-633-the-economic-benefit-of-improving-the-uk-nuclear-supply-chain-capabilities.pdf 84 See blog NOT A LOT OF PEOPLE KNOW THAT 10/5/14. 85 DECC (2012), Electricity Market Reform: Policy Overview, Annex E, Fig. 1.
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Sets prices for producers of low carbon electricity via contracts for differences (CfDs)
Decides on the mix of generating capacity
Allocates CfDs to low carbon electricity producers, which are a form of government spending, and which are limited by the Levy Control
The reason the system is currently tight is the combination of 1) the failure of DECC to seek a derogation to allow some of the coal plants to remain open (or just ignore the Directive), and 2) the EMR has taken so long that there is a risk of shortage since companies suspended investment in plant because of uncertainties, in particular the meal it has made of the capacity market. The initial storyline was that the capacity market would not be implemented if it were necessary, a statement which naturally ensured that few would start developing a plant until the rules were clear and the first auction was run86. The capacity market In its Project Discovery Ofgem noted:-
“As an increasing proportion of the market receives revenues via subsidies this will place downward pressure on the profitability of gas powered generation and thermal plant will operate at lower load factors to accommodate the variable output patterns of wind and other renewables. Flexible thermal plant will increasingly rely on either high prices in periods of system tightness to make an adequate return.”87
In order to support the subsidised windmills (and to a less extent the photovoltaic panels) which will increasingly both depress the price of the wholesale market and reduce the running time of thermal plant hence undermine their economics88. To financially support the thermal plant which are essential to back up the intermittent wind and solar, the government has introduced a capacity market. In 2005 American Miles Bidwell and I prepared a multiclient study “Assuring Generation Adequacy”, which reviewed capacity mechanisms in 12 jurisdictions around the world, and developed the concept of “reliability options” (ROs). Subsequently, acting for the Public Service Commission of Connecticut, Bidwell introduced the concept into the debate on the Forward Capacity Market in New England. It was accepted and working with four other economists and one systems engineer over a period of 5 months he developed the detailed rules in March 2006. The system was introduced with a first auction in February 2008. We prepared a supplementary paper translating the New England filing to the Federal Energy Regulatory Commission into English.
86 The only plant that has commenced construction in recent years is ESBI’s 880MW CCGT at Carrington which is due commercial operation early 2016. There was a provision in the legislation to ensure that it is included in the capacity market. 87 Ofgem (2010), Project Discovery: Options for delivering secure and sustainable energy supplies, p.18. 88 The German Ministry of Economics estimated in 2012 that the much greater volume of wind and PV in Germany depressed the market price by €9/MWh. In Italy Sorgenia (4GW of plant) is in administration and Edison’s generation (5GW) is having a financially hard time.
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In September 2010 I offered the study and the supplementary paper to Mr. Jonathan Brearley, who had come from DEFRA (which is not an obvious place to learn about something as complex as the electric industry89), and who was heading up the EMR. He responded “My team do not think it is relevant.” In December 2010 DECC commented in a Green Paper that ROs were “an interesting academic concept, that had not been applied in practice”. I repeated my point in a letter to DECC officials on 5 January 2011, and a couple of days later a young man rang me and asked me to provide information about ROs. I told him he could buy our study for £2,500, to which he responded “we have no money”, which in the light of the money spent on consultants is an absurd comment. I provided an article Bidwell had written, then heard no more. In the White Paper published in July 2011 there were pages on ROs. But unfortunately DECC had misunderstood their nature, commenting that they were financial instruments, which they are not – they are physical. Furthermore it envisaged that the penalty paid for not being available when called could increase to a value of lost load expected to be between £3k and £10k per MWh, and this would require a secondary market to enable generators to hedge their risk of incurring near the maximum penalty. This proposal not surprisingly attracted opposition from the generators. The penal approach based on economics 101 misunderstands the point of the penalty; the purpose is not to risk bankrupting companies but to provide them sufficient incentive to be available. (In any case provided the Minister – who is going to determine the capacity required – does not significantly underestimate the requirement, there should be little prospect of prices increasing to a high level. So why frighten the horses?). Having got the product wrong, the consultation responses were not helpful. Eventually in January 2013 DECC dropped the RO concept and plumped for an “Administrative Capacity Market”90, but unwisely continued with the concept of the value of lost load related penalty. Although the proposal for the market was set out in July 2011 and DECC employed first a Spanish consultant who had been involved in introducing ROs to Columbia then an American who was not involved in the design of the New England Forward Capacity Market, the discussions between DECC and stakeholders proceeded at a languid pace. Some of the stakeholders were concerned that DECC did not appear to listen – “consultation” was a one way street – and at best DECC only responded to concerns slowly. Thus, for example, it took six months for DECC to agree that generators are not liable for penalty if the grid faults and that participants can only “react” to an issue if there is a signal upon which to react.” It took generators more than two years with finally a squad of bankers to get DECC to understand that plant would not be financeable with a large penalty and to withdraw it. Finally DECC employed consultant CRA which had been involved in the New England Market, and eventually in June 2013 the design was finalised and the first auction is due to take place at the end of 2014, more than 4 years after the saga began. If DECC were not such an amateur organisation (deploying an ever changing cast of youngish unexperienced officials, which retarded progress), it would have sent someone to New
89 In March 2011 Mr. Brearley gave a presentation which included a slide that stated “No one is building a nuclear power plant against the regulatory asset base.” This is not correct. Georgia Power Company is building the Vogtle 3 and 4 Units in this way with a profit/risk sharing scheme between the company and its customers. This would have been a more intelligent way of developing Hinkley C than the approach adopted of a fixed “price” scheme. 90 The Italian regulator L’Autorita, has designed a market with Reliability Options.
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England once I had alerted it about the system there, and would have employed someone who had been involved in the capacity market. Instead of taking more than four years to first auction it could have been done in 3 if not 2½ years. The capacity market saga is a case study in serial incompetence. The unsuitability of the current CCGTs for balancing an increasing level of wind In July 2013 Mott Macdonald delivered to DECC “Technical measures for the mitigation of electricity imbalance risk” which DECC did not make a point of publishing91, apparently because “it was unhelpful”. The summary of section 4.2.1 “The need for flexible and fast expensive fossil-fired generators” states:-
“The CCGT fleet currently provides the bulk of the balancing power required to meet imbalance. The requirement for CCGTs to meet this demand will increase as coal plant is progressively shut down
Whilst existing CCGTs produce energy more efficiently at rated load, they have slower start up and stop times than either OCGTs or diesel generators – or the new breed of fast-response CCGTs such as General Electric’s Flex-efficiency 5029 and similar offerings from Alstom and Siemens. So whilst existing CCGTs are effective for balancing large predictable differences in demand (and they were designed to 2-shift to meet the difference between night and day demand) they are an expensive way to respond to increasing amounts of short term volatility presented by increased volumes of wind on the system92
If National Grid continues to rely on CCGTs that require say four hours ramp-up period, then it will continue to rely on a four hour weather forecast, which will be inherently more inaccurate than a forecast made say only 30 minutes in advance. This inaccuracy will lead to higher levels of imbalance and additional costs
Possible solutions here are either to build some additional and more responsive plant by investing in new flexible CCGTs that are able to ramp up and down more effectively. All these options93 clearly have a significant cost and will need careful evaluation prior to being implemented as policy”
91 I obtained it with an FOI request but it can be googled. 92 “The reason for the low fleet efficiency of the CCGTs is because, starting from cold, the gas turbine takes up to 40 minutes, firing fuel, before it can start exporting power. Typically, the steam turbine generator cannot begin to synchronise before 80 minutes into the start-up process and thus the CCGT cannot begin to deliver name plate performance until roughly two hours into the start-up procedure.” “In this mode, the current fleet of CCGTs operates at an average efficiency that is significantly lower than 50%, despite the important role of those delivering base load at close to 60% efficiency. This degradation of the heat rates of CCGTs has been observed in Germany with CCGTs reporting degradation of their heat rates up to 15% from nameplate efficiency, due to change in the operating regime from what they were originally designed for. This results in obvious increases of emissions and costs.” 93 “There are already fossil-fired generators, mainly gas or diesel-fired, that are more flexible and are able to ramp up and down quickly, and to start generating from “cold” within 15 minutes.”
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Notwithstanding what ill-judged policies DECC inflicts on the system I expect that by pulling out all the stops of demand side response and calling on standby generators, and in the longer term the provision of more flexible gas plant and diesels and some extra controllable hydro, National Grid will probably keep the lights on – BUT AT A COST. And cost is the part of the so called trilemma which DECC has not demonstrated the slightest concern beyond political prattle. The big questions The issue the Committee is examining is important, but there are arguably more important ones that Parliament has not examined and the government is resolutely ignoring. The first is how have we got into the situation I describe at the beginning. Next, as Professor Michael Kelly, Professor of Technology at Cambridge University, notes in his presentation “Future Energy Needs and Engineering Reality”, the enormous land area required for wind and solar and how expensive they are – in consequence subsidies have been cut in various countries. He also notes that Chinese emissions have grown each year over last 10 years by an amount equal to the whole of UK emissions. (To this I add that Germany and the Netherlands are commissioning 10 large new coal plants. On 27/8/14 Reuters reported the President of the German Energy Regulator as saying coal generation is necessary to reduce the risk from Russian gas). Kelly concludes “The current decarbonisation regimes will fail to meet their objectives…Noble causes are not helped by poor science or bad engineering.” The big question is whether all of this effort to decarbonise is worth it. The House of Commons Committee on Energy and Climate Change made an inept effort at addressing the question earlier in the year. Although it had some world class sceptic scientists make submissions and two who gave evidence, it ignored their evidence. (Perhaps because the chairman of the Committee makes so much money from renewables interests94). Finally there is a serious question to ask about the competence of DECC both to implement policies and to advise ministers of what is practical. Many years ago I spent two years in the civil service so I am aware of the relationship between ministers and civil servants. Thus something technical like the capacity market is down to civil servants, and the futility of burning wood chips to reduce CO2 emissions (supposing that was the purpose of the subsidies) should have been within the civil servant’s ambit. Likewise the ghastly and expensive mess DECC is making of smart metering (with an impending mess on the comms) is down to civil servants, see “A submission by Alex Henney to the Energy & Climate Change Committee on the roll-out of smart electric meters to domestic customers”, 2013, http://www.publications.parliament.uk/pa/cm201314/cmselect/cmenergy/161/161we02.htm, “Smart metering is FCUKED” by comms specialist Nick Hunn (http://www.nickhunn.com/wp-content/uploads/downloads/2013/11/Smart-Metering-is-FCUKED.pdf)95, and the recent critical Public Accounts Committee report “Update on preparations for smart metering”, HC 103 published 10/9/14. I can assure the Committee
94 The Daily Mail of 9 June 2013 pointed out that Mr. Yeo has been paid £402,033.88 by three green companies since August 2009. 95 Mr. Hunn commented to me that he attended a working group chaired by a young man who had recently got a classics degree from Oxbridge. One would have thought that after the serial failures of the civil service with IT projects this amateurism would have stopped years ago. Does the civil service never learn?
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that the roll-out will provide no “resilience” unless the ability to centrally switch off large numbers of meters when there is a shortage is counted as “resilience”. The story of residential customers responding to prices in a significant manner is a fantasy story; the proposed system will not facilitate this even if many people were interested enough to do it (which is doubtful). It would be far more effective from a resilience perspective to install smart white goods. But such a programme does not allow politicians to run around proclaiming they are “helping” us with a £10bn programme that will supposedly save us £5bn. The unrealistic decarbonising policies of Secretary Davey and many other politicians is due to group think about climate change to which many are signed up. The combination of civil servants who do not appear to understand much about the electric industry with politicians who have unrealistic policies means the lunatics really are running the asylum. 18 September 2014
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Alex Henney, EEE Ltd96 – Supplementary written evidence (REI0055) What goes around comes around – what to do with the electric market Freeing in industry in 1990 When it was owned by the government the British electric industry was not run just for the benefit of its customers. It was overmanned to suit the unions; the Central Electricity Generating Board (CEGB) bought plant in advance of requirement to provide equipment manufacturers with work; until Mrs. Thatcher broke the National Union of Mineworkers, it bought British deep mined coal which was not only expensive but was also unhealthy for the miners; and there was a decades long extravaganza with expensive nuclear power. The CEGB was a classic case of “lobbyist capture”. In my mind, and those of many others involved at the end of the 1980s, privatising the industry and introducing competition would subject it to the discipline of the capital markets, and get the industry away from government and all the resulting inefficient influences. This aim was achieved for seven years. The first benefit was that the cost of nuclear power was revealed; the programme to build more than Sizewell B was stopped; and over 5 years British Energy radically improved its performance. The next was that the National Grid and the two big generators National Power and PowerGen downsized by more than 50%. Finally there was a significant programme of building combined cycle gas turbines which displaced coal. The Department of Energy was shut, and most officials with industry knowledge left the civil service. New Labour gets fiddling So far so good. But with the election of New Labour in 1997 political interference returned with ever increasing enthusiasm and ever reducing competence. First came a gesture by Peter Mandelson to halt licensing of CCGTs to protect coal, which achieved nothing. Next came the ill-judged restructuring of the Pool, which had its faults but not the one which it was blamed for. It did not as claimed by the government and Offer facilitate the exercise of market power – that was due to the control of pricing by the duopoly of National Power and PowerGen (subsequently joined by Eastern Electricity, which became TXU Europe). The New Electricity Trading Arrangements for England & Wales (NETA)97, as an ill-judged and superficial change. Contrary to its billing, NETA did not reduce prices – they reduced six months before NETA was introduced because of a combination of overbuilding of CCGTs in
96 I was on the board of London Electricity 1981-84. My report “Privatise Power” published by the Centre for Policy Studies in February 1987 was the first to propose a competitive restructuring of the electric industry with a pool. After the election in June I was involved with Rt. Hon. Cecil Parkinson and officials in the early days of restructuring, and wrote a paper “The operation of a power market” which had an influence on the course of events. Subsequently I have advised on electric markets from Norway to New Zealand. Much of the factual material of the first three sections is taken from “The British electricity industry 1990 – 2010: the rise and demise of competition”, and some from “The expensive and ineffective shambles of Electric Market Reform”, a submission to the Energy & Climate Change Committee considering Electricity Market Reform, October 2014. 97 Subsequently extended to Scotland and named the British Electric Trading and Transmission Arrangements.
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response to National Power and PowerGen keeping prices up, and of the fragmentation of ownership following the part-forced and part voluntary divestment of 13GW of plant by National Power and PowerGen. The next step in ending the market followed Tony Blair’s wish to save the planet which developed over the years from 2002 when he published “The Energy Review”. Concurrently the government introduced the Renewable Obligation (RO) Scheme, which required suppliers to have a proportion of Renewable Obligation Certificates (ROCs) which were bought and sold at the margin in an ersatz market arrangement. The RO scheme suffered from “naïve marketism” – an ideological belief in the efficiency of “markets” (in this case a pseudo-market) regardless of practicality. The objective of increasing the contribution of non-market viable renewables generation is a public policy objective, not an economic objective. Thus its financing should not be impacted by the volatility of any market, let alone of three markets – the energy market; the CO2 market; the RO “market”98. The main facility being built – windmills – are very capital intensive, and their output is not correlated with the driver of the market, the price of gas. The consequence of these uncertainties, together with the uncertainty of the RO recycling scheme and the unlikely (but not inconceivable) possibility of a collapse in RO prices, piled artificially contrived bureaucratic risks upon the politically contrived risk of the EU ETS, and both upon a genuine (but irrelevant) market risk. These risks not only unnecessarily increased the cost of capital, but also made it difficult for new entrants to develop project financed schemes (as they have done in Germany). In consequence only companies with large balance sheets could join the game. In contrast, a feed-in tariff meets the low-risk financing requirement that is appropriate for a scheme based on public policy; provides the basis for project finance; and is simple; and is cheaper – the German feed-in tariff scheme was about 15% cheaper, but cost has never been of consequence to DECC. The government fiddled with the scheme making seven changes over the period to 2010. Along with renewables, led by Blair, the government reversed policy on nuclear and in the May 2007 White Paper on Energy proclaimed that it “believes that new nuclear power stations could make a significant contribution to tackling climate change.” In 2007 at the Spring European Council, and against advice, Blair signed up for the UK to achieve 15% consumption of all energy from renewables by 2020, which was the most demanding target of any member state and required the UK to spend about a quarter of the total cost of the EU meeting the 2020 objective for carbon reduction. The 15% target was subsequently converted by Secretary of State Ed Miliband into achieving 30% renewables in the electric industry. This could only be achieved with a great deal of wind, some pseudo biomass (namely new cut woodchips from the US which under many circumstances increases CO2), and token PV in our gloomy climate. While New Labour talked a lot it did not achieve much and did not achieve the targets which it set. The Coalition gets serious about wasting money and destabilising the electric market
98 In order to avoid the price of ROCs falling to zero, which would happen if the number of ROCs offered exceeded the year’s target, the target each year is set at least 10% above the expected RO outturn, which negates the point of the target.
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The Coalition continued with the same policy objectives but decided to discontinue the ROC scheme and replace it with contracts for differences which would also be used for nuclear, and would introduce a capacity auction to provide financial support for the dispatchable thermal plants that are needed to provide backup when the wind does not blow and the sun does not shine. The Coalition called the project “Electric Market Reform”, but in reality it was “Electric Market Replacement”. The consequences of the policy are that we are:-
Building the most expensive nuclear plant in the world costing £16bn (or £24bn including interest during construction) for 3200MW, throwing very generous profits at EDF
Subsidising residential solar panels in our gloomy climate with subsidies which make nuclear look cheap
Subsidising expensive (£95/MWh) - and for offshore, very expensive (£155/MWh) – wind which costs respectively two and three times the current wholesale price of electricity, and sending vast sums of money overseas. A blog “The UK Offshore Wind Industry”99 analysed Renewable UK’s report “Offshore Wind Project Timelines”. The paper analyses the subsidies payable to wind farms already operating or which will commence operation under the RO regime, and those under construction and likely completed by 2022. “With output of 62TWH p.a. gives an annual subsidy of £6 billion…and all guaranteed for 15 years…The share of UK companies Centrica and SSE only amounts to 17%, meaning that the vast bulk of subsidy will be sent abroad…The wind industry creates very little added value, while Siemens and Vestas dominate the manufacture of turbines.” When the “market” income from the subsidy is added to the subsidy we get to a total of £10bn p.a., which the author opines “the UK simply cannot afford.”100 Secretary of State Davey likes to publicise how much “investment” his policies have attracted in a similar manner to the way Prime Minister Brown boasted of the Public Finance Initiatives for hospitals which are now causing financial distress for many hospitals. Davey has claimed “The UK is the best place in the world for doing business in offshore wind”, and we are “leading the world.” We are definitely leading the world in subsidies. But we are in a one horse race – other countries are not so unwise as to follow our expensive example. The author regards all of this as “the economics if the mad house”
Throwing subsidies at wood chips from new cut trees in the US which often actually
99 NOT A LOT OF PEOPLE KNOW THAT, 5/1/15. 100 The Economist of 10/1/15 carried an article “Britain’s biggest export: wealth” which pointed out that because overseas returns have reduced “net investment income has fallen from a peak of 3% of GDP in the second quarter of 2005 to minus 2.8% today. That has caused the current account deficit to swell to 6% of GDP even as the trade balance has improved….This has worrying implications for the sustainability of Britain’s recovery.”
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increase CO2 emissions and destroys the environment101. Journalist David Rose went to North Carolina to see the operation by Enviva cutting down mostly hardwood trees to make into more that a million tons annually of pellets that are transported 3800 miles to Drax in Yorkshire to generate £62M in subsidy in 2013. Drax’s head of environment admits the wood fuel produces 3% more CO2 than coal and twice as much as gas102? DECC falsely claimed to Rose that Drax only uses wood “unsuitable for sawmilling because of small size, disease or other defects”
Banking on the unproven prospects of Carbon Capture and Sequestration (CCS) which is a saga that started in 2003. Recently E.On in the Netherlands pulled out of developing perhaps the most favourable project of installing a post-combustion system of 250MW on a new coal plant it is building at Maasvlakte; after a decade Vattenfall is reported as stopping research on CCS; the costs of renovating and installing CCS to the 30 year old Boundary Dam power plant in Saskatchewan is very high, and incurs a parasitic loss of about 32% of the plant’s power and there is a thermal efficiency loss of at least 25%
One of the notable features of the wind effort is that it does not achieve what it claims on the tin by way of mitigation of CO2. As the wind output goes up and down so the plants balancing and offsetting the wind must go down and up. If the plants are not controllable hydro, but are (mostly) thermal as in Britain, their thermal efficiency will reduce and their output of CO2 will increase beyond their normal level. This is shown for Ireland and the US in an article I wrote with Dutch physicist Fred Udo103, in which we recommended that there be an independent – a genuinely independent – review of the effectiveness of windmills in reducing CO2 emissions. I sent it to the then Minister of Energy, and got a three page reply from DECC. This demonstrated that DECC did not understand the issue and furthermore it had no wish to undertake any study, let alone an independent one104. DECC has no interest in evidence based policy, only policy based evidence. And notwithstanding the statements made about reducing CO2 the real target appears to be to increase renewables production to meet the EU 20/20/20 Directive - the means has become the end. The financial effects of a significant level of subsidised renewables on thermal plant are:-
Reduce the running hours of thermal plant
Increase wear and tear from frequent stops and starts of the plant that balances the variability of wind105
101 DECC produced a report “Life Cycle Impacts of Biomass Electricity in 2020”, July 2014, which went in great detail into the CO2 consequences of many variants of wood residue/chips of which the higher volume variants, such as cutting down intensively managed plantations, do not reduce CO2 emissions when account is taken of sequestration from cutting and regrowing the forest But it carefully did not point out that the CO2 mitigation from the expensive subsidy paid to Drax is negligible. Perhaps all the cases were included to obfuscate the basic issue. 102 The bonfire of insanity, Mail on Sunday, 16/3/14. 103 “Wind – Whitehall’s pointless profligacy”, New Power, Issue 45, October 2012. 104 “DECC’s response to Wind – Whitehall’s pointless profligacy”, New Power, Issue 47, December 2012. 105 Power Plant Cycling Costs, by N. Kumar et al for the US National Renewable Energy Laboratory, April 2012. The study provides estimates of cycling costs – operations and maintenance, start-up costs, next rate costs -
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Reduce the level of the market price – the German Ministry of Energy estimated a reduction of €9/MWh in 2012. One of the consequences of subsidising the output of windmills is to create negative prices (64 times in Germany in v2014) – the higher the subsidiy the lower the price will go – which are not beneficial to thermal plants
These changes caused financial distress to owners of thermal plant as shown by Sorgenia in Italy (5GW), which went into administration, and RWE in Germany which lost money in 2013 for the first time since the war and E.On. In recent years the share prices of both companies have performed poorly compared with the DAX. At the beginning of 2008 the German DAX stock index peaked at 7949 then, following
the financial crisis of the autumn, it more than halved to 3710 at the beginning of March 2009, to recover to 9870 at the beginning of 2015. Over the period the DAX increased by 24%. Between the beginning of 2008 and 2015 the share price of both RWE and E.On reduced by about 70% and by about 75% relative to the DAX.
While the massive loss of value is due to several factors – highly priced gas contracts, the government’s decision to close nuclear plants, and reduction in consumption - part is due to the effect of renewables. The Levy Control for 2020 is budgeted at £7.6bn (2011/12 prices) most of which is for electricity decarbonisation measures which DECC estimates106 will add an average £92 (2014 prices) on household energy bills by 2020 of which about 4/5 will be on electricity. This figure understates the total cost to households because what they do not pay for directly in their energy bills they will pay for indirectly in the higher cost of goods and services. Domestic consumption is 36% of total consumption; allowing (perhaps generously?) for 5% going into goods and services exported, then the 27.4M electric consumers will pick up about £210 in 2011/12 prices. DECC’s Impact Assessment for 29% renewable electricity assessed the present value of its cost up to 2030 as £39bn offset by carbon savings valued at £6bn leaving a net cost of £33bn”107, which does not seem a good deal. Now with Davey’s ill-founded story that since
and the impact on forced outage rates for various types of plants for hot starts, warm starts, and cold starts. The report comments of older combined cycle units that “when operated in Cycling Mode they can have a higher cycling cost compared to a unit specifically designed for cycling.” Mr. Kumar added “Depending on the vintage, operating regime, etc. and importantly design features a plant would have anywhere from 110% to 300% increased cycling related cost compared to a baseload unit. This means that a typical plant that may spend about $1-1.5M on annual baseload “wear and tear costs”, if cycled heavily (say daily) could spend almost $3-5M just to maintain current reliability (again, this is wear and tear costs, not total maintenance cost). If this is not spent the plant will face significant life shortening and/or will be unavailable due to increased forced outages.” 106 Estimated impacts of energy and climate change policies on energy prices and bills, DECC, November 2014. 107 Impact Assessment of proposals for a UK Renewable Energy Strategy – Renewable Electricity, DECC, URN 09D/686, 10 July 2009, http://www.decc.gov.uk/assets/decc/what%20we%20do/uk%20energy%20supply/energy%20mix/renewable%20energy/renewable%20energy%20strategy/1_20090715120351_e_@@_ukrenewableenergystrategy2009iaforrenewablecentralisedelectricitysectorurn09d686.pdf.
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oil and gas prices were every going up, hence renewables and nuclear would be cheap has been shown to be unfounded108, we should surely reconsider our generation policies. In “A Crisis in UK Energy Policy Looks Inevitable”, investment analyst Peter Atherton opined:-
“The UK looks increasingly certain to be heading for a crisis in its energy policy in our view. The crisis is likely to come to a head via either: 1) a huge spike in wholesale prices as the power market anticipates a short term shortage of physical capacity; or 2) a longer term shortage of dispatchable generation capacity that puts security of supply at serious risk, or 3) through spiralling consumer costs that will inevitably force a future government to renege on its policy commitments; or 4) sharply rising profit levels reported by developers coinciding with rising consumer bills which become politically unacceptable to the government of the day. There is a high probability in our view that several of these catalysts could combine together to create a ‘perfect storm’ of a crisis within the next decade. If this happens then there will be three casualties in the crisis – the government of the day, the consumer, and those investors who have thus far funded the policy.”
The demise of the market and what should be done with it? We have reached the situation where DECC determines the type and volume of new plant that will be built and much or even most of the income that renewables and nuclear plant will receive. As auction is run where it determines the volume of other plant required, which determines the plant retired and new (generally gas) plant built. Then at the retail level the suppliers have to a degree been turned into welfare organisations with social tariffs and energy efficiency initiatives, and the green deal. Real commodity markets achieve several related economic objectives. In the short term they provide a signal indicating shortage/surplus, and hence how much plants of different costs should produce. They also provide an incentive to be efficient. Over the longer term they provide (with judgment and luck) an indication of the need to close and to open plant and to innovate all in a decentralised manner. Finally they remunerate capital investment. Our arrangements do not qualify as a commodity market. While markets can accommodate normal commercial risk, they are not good at handling political risk and the effect on the share prices show investors can be hit hard. The story of the last nearly two decades is that politicians cannot resist interfering with the electric
108 Anyone with any knowledge of the history of oil prices and of the number of misforecasts would know that such forecasts are a mug’s game. But then DECC with its ever charming staff, let alone Mr. Davey, has virtually no corporate memory of either the oil and gas markets or the electric industry.
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industry, and have undermined the generation market109. The government got Ofgem to refer the retailing to the Competition on Markets Authority in June 2014. In September 2014 Miliband wanted to legislate to fix prices, and the share prices of Centrica and Scottish & Southern Electric dropped by 20% relative to the FTSE 100 over four months.
After oil and gas prices reduced, in January 2015 a Treasury spokesman was quoted that “The government is conducting studies of the industry”, and Labour wrote to Chancellor Osborne claiming that the government consistently refused to act on evidence that consumers were being ripped off. Labour had an Opposition Day Motion on 14 January proposing that Ofgem be given the power to cut prices. Step by step regulation by the back door has been ratcheted up both of generation and supply. In “The road to re-regulation”110 Professor Dieter Helm arrives at the same conclusion about the move to regulation and points out that an increase in regulation undermines competition. He observes “Contrary to the mantras trotted out on all sides about it being a competitive market, most is not.” Helm argues for a fundamental review to address “whether to build a proper working electricity and energy market, or to re-regulate and go back to state planning and state price‐fixing. Either is probably preferable to the current position.” He points out the case for full nationalisation is that “without competition there is not much point in paying a private sector cost of capital, when the state can borrow at much
109 In its submission to the Competition and Markets Authority Energy Market investigation dated 14/8/14 EDF Energy commented “The energy sector is by its nature heavily regulated and subject to continuous regulatory, political, government and EU influence.” 110 Energy Futures Network, Paper No. 7, http://www.dieterhelm.co.uk/node/1387.
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less. Why pay EDF and the Chinese nuclear companies around 10% real rate of return for 35 years, when the Treasury can borrow at around 2%?” I suggest we forget a market and accept that the government will determine the generation mix. If we wish to keep the industry in private ownership we could set up a central buying authority that would plan the system, select plants by auction, and ensure that they receive a regulated rate of return as they do in some US states (such as those in most of the south) where there is no wholesale market. The capital investment is remunerated with an allowed rate of return plus an opex cost for maintenance, and the payment for fuel is passed through. There could be a short-term energy ersatz price market at the margin to provide a scarcity signal for customers to respond to, and to provide a bonus to generators which out-perform at times of shortage. All of the costs for all of the plants would be “blended” to create a time-of-use Bulk Supply Tariff priced roughly on a marginal basis as the CEGB did. So we will have come full circle and the politicians can mess around without requiring expensive restructuring arrangements. 21 January 2015
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Honeywell – Written evidence (REI0019) Introduction The House of Lords Science and Technology Select Committee is conducting an inquiry into the resilience of the UK’s electricity infrastructure. In addition to The Committee investigating whether there will be enough electricity to meet future demand and how resilient the UK’s electricity generation, transmission and distribution infrastructure is to sudden, unexpected events, it will look at the role of science and technology in ensuring a resilient electricity system and ask how well the UK is placed to exploit new technologies. This is an area in which Honeywell has a great deal of experience on a global scale. Honeywell welcomes the call for evidence from the Select Committee on Science and Technology and has submitted this paper in response to seven questions, which we believe Honeywell can offer relevant answers. There are some common themes that arise in these answers as they similarly address a number of areas of interest to the Committee. Honeywell Response Executive summary Honeywell is a Global Company with extensive experience of working with Governmental Energy Departments and Energy Regulators and providing tailored Demand Side Response (DSR) solutions for Utilities and DSR Aggregators around the world. Honeywell believes that DSR technology could have a revolutionary impact on helping to improve the resilience of the UK’s electricity infrastructure in a simple and cost effective manner as proven by its application for managing supply-demand issues across the world. Indeed Honeywell’s DSR solution is in wide use across the USA and being delivered at a global level, being the first Automated Demand Response solution to be implemented on a wide scale in India, China, Australia, Hawaii and the UK. Using open standards, it is also being promoted as the DSR solution of choice by Energy Regulators in a number of these countries. Honeywell has also been involved in energy efficiency for over 100 years and will continue to support the cause of energy efficiency in UK, whether it be demand reduction, demand management or green house gas emission reduction. While the potential for DSR in the UK is significant, (1.2-4.4 GW from non-domestic buildings alone, see ‘Demand side response in the non-domestic sector’, Element Energy July 2012), much of the DSR accessed today is fossil fuelled additional generation. This is expensive, wasteful and generates unnecessary carbon emissions. It is estimated that spinning reserve stations in the UK are responsible for over two million tonnes of CO2 emissions every year.
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We call this ‘Dirty DSR’. By turning down or off or cycling electrical loads in commercial and industrial facilities, DSR can be provided which emits no carbon emissions, is reliable and can be accessed quickly with little or no impact on the building occupants or building operation. We call this ‘Clean DSR’. The technology exists today to cost effectively provide clean DSR and National Grid, Utilities and DNOs have all expressed a desire to access clean DSR as they seek to meet their obligations of creating market mechanisms and solving operational challenges which contribute towards a low carbon economy. The impact of DSR can be significant. For example, water utilities alone are responsible for around 1% of the UK’s total electricity consumption – mainly for pumping water. Globally, water utilities are major participants in demand response programmes and similar potential exists for the UK’s water companies to benefit by aiding National Grid and DNOs with flexibility in how they operate their pumping systems. With much of this DSR accessed by turning electrical load down temporarily in buildings in an automated fashion without adversely affecting the building’s performance or comfort conditions, the UK’s significant building stock can therefore be considered as potential ‘storage facilities’, offering a flexible resource which can help to manage the grid at times of stress (such as when power stations trip out or wind farms can’t operate in still weather), in a fast, reliable and cost effective manner. DSR technology such as Automated Demand Response (ADR) can also be used to turn on electrical plant in an automated, reliable and controlled fashion across the UK’s facilities. This enables wind generated electricity, typically during the night at times of low demand, to be used effectively, avoiding payments to wind farm operators to spill the electricity in a wasteful manner. Employing open communication standards for DSR allows for the greatest number of competitive offerings and participants. It also enables National Grid and DNOs to avoid being locked-in to a single provider’s proprietary technology. Honeywell believes that Clean DSR should be valued above Dirty DSR and as such should receive priority when called on as well as have a higher economic value. To do this, DSR providers need to see clear and transparent pricing as they decide who and where to provide DSR and create a healthy and competitive market. DSR Aggregators need the surety of long term DSR provision to enable business models to be attractive and so long term contracts need to be offered, well beyond the one year term currently proposed under the Capacity Mechanism, justifying the significant investment they need to make in a DSR solution infrastructure. The Committee invited responses addressing some or all of the questions in its Call for Evidence paper. Honeywell has provided answers to seven of these questions:
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Short term (to 2020)
1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base?
Answer
The UK’s electricity supply is “uncertain” for the next few years and as soon as this winter as the National Grid admitted this month (September). This was confirmed by it bringing forward the planned launch of the tender for its Supplemental Balancing Reserve (SBR), to manage fluctuations in supply, by a year. This is in addition to the launch of its new DSBR service which seeks to enable National Grid to reduce electricity demand by over 300MW this winter when required and far more the following winter. In June, National Grid had said the emergency plan to boost electricity supplies would not be needed this year but it only took several power plant closures and unexpected problems on the network for this outlook to drastically change. As the Large Combustion Plant Directive causes large quantities of further generation capacity to be closed down in the run up to 2020, exacerbating the problem, the resilience of the UK’s electricity system seems ever more fragile. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’?
Answer National Grid has recently launched is DSBR service to enable over 300MW of electricity demand to be turned down as an emergency action should electricity demand be forecast to exceed supply. However, National Grid is proposing to provide dispatch signals to load reduction providers in a very simple, one-way fashion, to their ‘phones, PCs or tablets. National Grid will also verify that the sites tendered are capable of providing the quantity of demand reduction offered by validating this against metered volume data from the previous winter. While National Grid is developing a low-cost solution to manage the DSBR service which may not be used after 2017/18, we believe that simple, two-way, low-cost solutions exist today, which would provide a far more sophisticated, reliable and accurate verification and management system. These systems are ‘cloud based’, meaning that they are constantly updated at no extra cost, there are no development costs or server costs and the license can be cancelled when the system is no longer required. These systems employ the internet using open signaling standards; an important consideration. Systems employing open standards would facilitate the development of an inclusive and competitive service market for DSBR, from both individual facility owners and third party service providers. This also enables any building using these standards to participate. It also means that National Grid and building owners would
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avoid being locked-in to a single provider’s proprietary technology.
2. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? And
3. What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
Answer
Demand reduction from UK facilities can not only play an important role in helping manage our electrical grids in times of stress but at the same time make a major contribution to achieving the country’s carbon reduction targets. Valuing the carbon impact of Demand Side Response (DSR) would provide a greater emphasis on delivering demand reduction measures. Currently carbon is not taken into account when valuing DSR. DSR from fossil-fuel fired, standby generation with a high carbon emission level (Dirty DSR) is economically valued equally with demand side load reduction which produces no carbon emissions (Clean DSR). We believe two main changes need to be made:
a. Clean DSR should be given priority over Dirty DSR when called for balancing services by National Grid or load shifting by DNOs ie have higher ‘merit’.
b. Clean DSR should be economically valued higher than Dirty DSR by factoring in the carbon emissions each produces.
These measures would significantly incentivise investment in DSR resources by third parties and service providers and enable the UK’s electricity system be managed in the most carbon effective way.
4. Will the next six years provide any insights which will help inform future decisions
on investment in electricity infrastructure? Answer This month, a study involving the globe's biggest institutions, including the UN, the
OECD group of rich countries, the International Monetary Fund and the World Bank, and co-authored by Lord Stern, concluded that tackling climate change can promote prosperity as long as the global economy can be transformed within the next 15 years. The first six years of this are a critical phase of this transformation.
The EU and UK are already committed to addressing climate change through regulation and incentives, having set mandatory emissions reduction targets. This should be taken into consideration when designing market mechanisms which seek to balance the electrical grid at times of stress. Clean DSR is a proven, cost effective and reliable solution which if promoted, can make a major contribution towards helping manage the grid whilst also minimising the UK’s carbon emissions.
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Long term (to 2030)
5. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
Answer
While the potential for DSR in the UK is significant, (1.2-4.4 GW from non-domestic buildings alone, see ‘Demand side response in the non-domestic sector’, Element Energy July 2012), much of the DSR accessed today is fossil fuelled additional generation. This is expensive, wasteful and generates unnecessary carbon emissions. It is estimated that spinning reserve stations in the UK are responsible for over two million tonnes of CO2 emissions every year. By turning down or off or cycling electrical loads in commercial and industrial facilities, DSR can be provided which emits no carbon emissions, is reliable and can be accessed quickly with little or no impact on the building occupants or building operation; ‘Clean DSR’. The technology exists today to provide ‘clean DSR’ in a fast, reliable and cost effective manner and National Grid, Utilities and DNOs have all expressed a desire to access clean DSR as they seek to meet their obligations of creating market mechanisms and solving operational challenges which contribute towards a low carbon economy. Flexible Load – A large, clean, untapped resource that exists across the UK To maintain the daily comfort and working conditions staff and visitors require, commercial and industrial buildings use electricity to power a range of devices such as lighting, heating, cooling, ventilating, air conditioning systems, pumps, fans and motors. For example, water utilities alone are responsible for around 1% of the UK’s total electricity consumption – mainly for pumping water. However, the electricity to these devices can be turned down or off for short lengths of time without adversely affecting the building’s performance or comfort conditions. This is called the building’s ‘Flexible Load’. When flexible loads are aggregated across many sites in a co-ordinated and automated fashion, a ‘Virtual Power Plant’ (VPP) of negative watts or “Negawatts” is created. Negawatts can provide significant operational and financial value to National Grid and DNOs across the UK. As a result National Grid and the DNOs will pay for the value a building’s flexible load provides based on the contribution the building makes. Flexible load can be delivered either directly by the building owner or via third party service providers (aggregators).
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Flexible Load is a unique asset which is virtually untapped in the UK. This is due to three main reasons:
National Grid’s balancing services programmes have, until only very recently, not included DSR resources. Today their use is still based solely on economic merit. As a result, payments have favoured generation over demand reduction. DNOs simply replace constrained distribution assets with larger equipment and not considered using demand response to manage existing assets.
A lack of technology solutions which can deliver flexible load in a cost-effective, reliable, fast, automated and scalable fashion for National Grid and DNOs.
A lack of awareness by the UK’s building owners of the value their flexible load could provide and how they could participate to offer it to National Grid and DNO demand response programmes.
Automated Demand Response - A new, simple but highly effective solution Automated Demand Response (ADR) is a proven technology solution with many Giga Watts of “negative load” already being utilised to reduce demand with success, in other parts of the world such as the USA, China, India and Australia. And recently ADR has been implemented for demand response programmes in the UK. ADR addresses point 2 in the list immediately above. ADR brings full automation to demand response by implementing automated market participation for National Grid, DNOs and building owners. Its functionality supports programmes that range from simple electricity load curtailment to complex time of use, dynamic pricing and customer bidding. Demand Response event and tariff information from National Grid and DNOs is turned into standardised ‘OpenADR’ signals which are received via the internet by an Open ADR Gateway device located on each building participating in the ADR programme. The Gateway will trigger an appropriate action based on the set of rules defined for the event and pre-approved by the building owner. This enables highly predictable electricity load reductions to be automated in direct collaboration with building owners in a way that has no impact on the building’s performance or comfort conditions for its occupants. ADR can also be used to turn on electrical plant in an automated, reliable and controlled fashion across the UK’s facilities. This enables wind generated electricity, typically during the night at times of low demand, to be used effectively, increases the consumption of base load nuclear generation overnight and avoids negative electricity prices and payments by National Grid to wind farm operators to wastefully and expensively ‘spill’ the excess. The Important Role of Open Standards – Enabling Competition & Protecting Building Owners
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While in many parts of the world, including the Unites States, automation of Demand Response programmes is widely accepted as an effective industry solution for shifting and shedding electric loads, unfortunately, many of the industry solutions available today are not standardised, creating problems for TSOs, DNOs, Demand Response Service Providers (Aggregators) and Regulators. The Open Automated Demand Response (OpenADR) Alliance was formed to accelerate the development, adoption and compliance of OpenADR standards throughout the energy industry. Indeed, a number of Regulators in the US now mandate the use of the OpenADR standard for all demand response programmes. The European Commission supports their use in Europe. The OpenADR standard allows any building using OpenADR compliant hardware to understand event or tariff messages and respond in an automated fashion. OpenADR is a communications data model built upon Internet Standards including XML and much of the complexity of the Demand Response programme is translated into simple signals for the building’s existing control system. An open protocol allows for the greatest number of competitive offerings and participants. The use of open standards is an important consideration for the UK Government as it facilitates the development of an inclusive and competitive service market for demand response going forward. This enables any building using a simple, low cost (hundreds of GB pounds, not thousands) OpenADR Gateway or OpenADR compliant plant (increasingly being developed by manufacturers) to participate. It also enables National Grid and DNOs to avoid being locked-in to a single ADR provider’s proprietary technology. OpenADR leverages existing building controls and open protocol communication standards to help lower the cost of delivering ADR. For more information, visit the Open ADR Alliance, an independent industry global association (http://www.openadr.org/) which supports the adoption of OpenADR for demand response.
6. Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
Answer
While we welcome the inclusion of DSR resources in the UK’s upcoming Capacity Mechanism, the proposed one year Capacity Mechanism contracts are currently far too short for DSR Aggregators to justify the significant investment in ‘clean’ DSR required to access the minimum provision levels (eg 3MW for National Grid’s STOR programme). Conversely, generation assets are offered 15 year contracts. We believe the decision to offer only one year contracts is due in the main to an ignorance of modern DSR solutions by the Capacity Mechanism designers and the belief that DSR involves buildings simply turning electricity off and on manually when requested.
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While modern DSR technology is fast, simple, reliable, proven and very cost effective, for example, to provide 3 MW of clean DSR can entail connecting and aggregating the flexible electrical demand load from over 15 large buildings. To do this, DSR Aggregators must invest in:
a. The IT system infrastructure required to monitor, control, action and audit DSR events – most often an annual software license.
b. The set-up and running of an operations centre, including staff. c. The building audits, load shedding strategy design and controls technology
required to connect buildings to the system. d. The incentive payments the DSR Aggregator must pay building owners for
their availability and participation in DSR calls.
Lengthening contracts for DSR would greatly improve the attractiveness of investing in its provision.
19 September 2014
Professor Gordon Hughes, University of Edinburgh – Written evidence (REI0049)
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Professor Gordon Hughes, University of Edinburgh – Written evidence (REI0049) Renewables and the resilience of the GB electricity system Context 1. Public debate about the impact of energy policies on the GB electricity system has
tended to focus on the probability of power cuts: Will the lights go out? This formulation is almost certainly wrong. Over the last 20 years a number of rich and middle income countries and regions have experienced serious power shortages. In all cases, these can be linked to the coincidence of several factors, with three important elements:
a. a sharp and unforeseen increase in demand, usually due to rapid economic growth;
b. poorly-designed or perverse incentives for investment in new capacity; and
c. a prolonged drought leading to a shortfall in hydro generation, often exacerbated by bad forecasting and mistakes in the management of hydro resources.
Despite the limited reserve margin, current prospects for economic growth mean that prolonged power cuts are very unlikely to affect the GB market during this and next winter so long as no more nuclear plants go offline. The short term reserve (STOR) program should provide sufficient resilience to cope with the loss of smaller thermal units.
2. Power cuts are a dramatic manifestation of a lack of resilience in an electricity system. What is less apparent but more important in the longer term is the cost of the measures required to ensure security of supply. Relying upon short term reserves is a national variant of the way in which industries and institutions respond to unreliable power supplies around the world. They invest in backup generators and multi-fuel equipment. Such measures can offset the unreliability of the public electricity system, but at a cost which will discourage investment or prompt businesses to relocate. From an environmental perspective, the thermal efficiency of alternative generation tends to be low and its carbon emissions are much higher than for modern large scale plants.
3. The UK has a temperate climate and, when compared to most of the world, it does not suffer from frequent extreme weather events. In the past, the cost of ensuring the reliability of electricity supplies has not been high. The cost of resilience has increased along with the share of intermittent renewables in total capacity. That trend will accelerate as the GB market moves to meeting the 2020 target of at least 30% renewable generation. In this evidence I examine the costs of (i) operating the Balancing Market, (ii) hedging price variability for customers, and (iii) ensuring investment in backup generation capacity. The estimates cited are based on work carried out in conjunction with the Renewable Energy Foundation that has been published or presented at conferences & workshops over the last 2 years.
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The cost of providing Balancing Services 4. Electricity supplies and generators pay a volume-related charge, known by the
acronym BSUoS, which compensates National Grid for the costs which it incurs in managing system-wide Balancing Services – i.e. ensuring that demand and supply match at all times. These costs include the provision of operating reserves including the STOR program, payments to generators that are constrained off the system due to grid bottlenecks, and other items.
5. Using data for half-hour Settlement Periods, it is possible to identify how the overall balancing cost is affected by total demand and the level of renewable generation. This involves careful statistical modelling because a key component – the system buy price – itself depends upon some of the variables which affect other balancing costs. There are also complications associated with the role of embedded wind and solar generation, i.e. units which are connected to the lower voltage distribution system rather than the high voltage transmission grid. Nonetheless, it is possible to obtain good estimates of how variations in wind output from grid-connected units affect balancing costs.
6. In May 2014 the NAO reported to the House of Commons that:
“Total balancing costs have shown a rising trend from £642 million in 2005-06 to £1,002 million in 2013-14. This overall trend is largely because of a rise in constraint costs …” My estimates indicate that total balancing costs would increase to about £1.7 billion if the Government’s 2020 target for renewable capacity were to be met under the weather and demand patterns of 2013-14.
7. An increase of £700 million may not seem large in relation to the full costs of supplying electricity, but it encompasses a much starker picture. For each additional MWh of wind output in 2013-14 the extra cost of balancing the system was £9.9 when wind output was 1,000 MW. This marginal balancing cost rose to £18.8 per MWh at an output of 6,000 MW. Over 2013-14 the average system buy price in periods when wind output exceeded 6,000 MW was £51.1 per MWh. That represents the market value of an additional MWh of generation to the system during such periods.
8. During periods of high wind output in 2013-14 an on-shore wind operator would receive a contract price of about £50 per MWh plus subsidies worth up to £48 per MWh. In addition, it imposed costs on all other users of the network amounting to nearly £19 per MWh. The net economic value of marginal wind generation was less than £33 per MWh but the price paid to the operator was more than three times that economic value. If the results are extrapolated to take account of the 2020 target, then the marginal balancing cost at high levels of wind output will reach £34 per MWh, reducing the net value of marginal wind output to less than £17 per MWh.
9. It may be argued that investment in the transmission system will reduce balancing costs associated with grid constraints by removing the costs of reducing output from some plants and increasing output at other plants in order to meet total demand. From a narrow perspective this may be correct, but only because the costs of intermittency have been transferred from the Balancing Market to transmission
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(TNUoS) charges. It will never make economic sense to attempt to remove all or most grid constraints. Pursuing that goal would require investments in the grid that would be heavily underutilised because wind output is so variable.
10. The real problem lies in a perverse set of incentives. The costs of ensuring resilience for the system are borne by everyone rather than by the renewable generators who are the source of the costs. It is not easy to design and implement mechanisms by which the costs of intermittency and grid constraints are covered by those responsible for them, but it would be possible to get closer to an efficient outcome than at present.
11. The defects of current incentives undermine a critical element of any long term solution, which is storage of intermittent power. In effect, the system should reward private agreements between groups of wind generators and nearby storage operators by which intermittent generation that might be constrained is, in effect, diverted to storage. This would require a restructuring of both BSUoS and TNUoS charge plus, perhaps, investment in transmission links to ensure that storage transfers do not impose constraints on the rest of the system.
12. As an illustration, Scottish Power controls a large wind generator with more than 800 MW of capacity in Scotland as well as the Cruachan pumped storage plant, which is being extended from 440 MW to 1,040 MW. Under current arrangements there is no incentive for the company to integrate the operation of its wind and pumped storage capacity. The reasoning seems to be that it is more efficient to integrate intermittent generation and storage for the whole GB market. The argument would be valid if marginal balancing and balancing costs were small and did not vary much over time or geography, but those assumptions bear no resemblance to reality. Instead, the structure of both balancing and transmission charges should be modified to bring them closer to the marginal costs incurred over time and space.
Price volatility 13. Though it may surprise some people, the GB electricity system should have a
relatively low volatility of system prices across times of day or seasonally. The reason is that the marginal system price – i.e. the marginal cost of operating the most expensive plants required to ensure that supply and demand match – is usually set by gas CCGTs, most of them built in the 1990s, for most of the time. They differ somewhat in efficiency and the price they pay for gas, but in 2013-14 the system buy price was between £40 and £60 per MWh for 50% of hours in the year (the interquartile range).
14. The construction of more renewable capacity will change this. Their marginal operating cost is very low, so when wind is available they displace gas and coal plants. The consequence is that gas plants expect to operate for a smaller number of hours in the year and will become unprofitable, especially if major upgrades are required to comply with EU environmental rules. When there is plenty of wind the system price will be determined by the marginal cost of operating existing coal plants, which is £25-35 per MWh using the current steam coal and carbon floor prices. However, when there is little wind the system price will be determined by the marginal cost of operating the least efficient gas CCGTs or even modern gas turbines
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if a large proportion of the older CCGTs are retired. In either case, the system price is likely to be £65-75 per MWh at 2013-14 prices.
15. Overall, it is reasonable to conclude that the interquartile range for the system price will increase substantially, perhaps doubling to £30 to £70 per MWh. The change in the distribution of prices will be asymmetric. Coal plants will set the minimum system price at the bottom end of the distribution (the 1st percentile was £28 in 2013-14), whereas the top end of the distribution is likely to increase substantially (the 99th percentile was £117 in 2013-14).
16. Shifts in the distribution of prices of this kind will substantially increase the cost of hedging electricity prices for suppliers and consumers who do not wish to be exposed to real-time volatility. A study published by Ofgem in 2013 suggested that the typical price of hedging electricity prices was in the range £50 to £60 per MWh during the period from 2009 to 2011. If the distribution of the system buy price were to change as discussed, the average cost of hedging would increase markedly.
17. A part of the cost of hedging is insurance against changes in the general market level of prices, which is closely linked to changes in the international gas market. An increase in gas prices will push up the top end of the distribution of system prices (when gas plants are required to make up for a lack of wind generation) but it will have only a small impact at the lower end of the distribution. Given the path of international gas prices and hedging costs from 2004 to 2011 it is unlikely that potential movements in gas prices could account for more than 40% of the overall hedging cost during the period 2009-11.
18. While it is difficult to be precise, it is likely that the increase in the volatility of system prices due to the larger share of renewables in total generation may be expected to push up the cost of hedging consumer prices by at least £40 per MWh. Of course, energy suppliers often choose not to hedge at all or only to hedge a part of their purchases, particularly if they can offset gains or losses in their supply business against matching changes in their generation business. Such within-company hedges may be less attractive as the volatility of system prices increases or if the composition of a company’s generation portfolio is skewed to certain categories of generation. For this reason it is not possible to say how much of the expected increase in hedging costs will be passed through to residential or non-residential customers. However, it is almost certain that suppliers without significant generation businesses, mostly new entrants to the market, will be more severely affected by the increase in price volatility than the larger companies with supply and generation businesses.
Investment in backup generation 19. The analysis above is relevant to the cost of ensuring that there is adequate
investment in new generation capacity required to ensure reliability of supply when wind and solar generation is low. Depending upon the rate at which older gas CCGTs are retired, getting to a conventional reserve margin of 15% over peak demand in the early 2020s may require the construction of 15-18 GW of new capacity during the next 5 to 8 years. Almost all of this capacity will be gas-fired but most of it will operate at very low load factors. The expected load factor for all gas plants over a period of years would be 30-35% but this would fall below 20% in windy years. Since existing CCGTs are likely to capture a substantial share of the market, any well-
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informed investor would not expect to achieve a load factor greater than 30% for new plant. Up to 2005, an investor would assume that a new CCGT would achieve a load factor of at least 65% and perhaps as high as 85%. In addition, the energy margin between the system price and the variable costs of fuel and O&M is likely to be small for most operating hours, so that the contribution to cover the capital costs of a new plant may be negligible.
20. At this level of usage it is difficult to justify building a new CCGT. Instead, investors are likely to opt for flexible and efficient single cycle gas turbines. That is exactly the pattern that can be observed in countries like Ireland, Brazil and the US where there are capacity markets or similar incentives to build plants to provide backup when there is a shortage of wind or hydro generation. The capital cost of such plants is about £350,000 per MW of capacity. They incur an annualised availability cost of £50-55,000 per MW per year, equivalent to £0.9 -1.0 billion per year for 18 GW of capacity. Fuel and variable O&M costs would be covered by the market price if they were required to operate. This figure provides a reasonable estimate of the long run cost of ensuring that there is sufficient spare capacity to match the intermittency of wind and solar generation.
21. The initial capacity market auctions will be dominated by bids relating to the refurbishment of existing coal and gas plants, but this will only marginally affect the amount of new capacity that is required to match the expansion of intermittent renewables. The price cap of £75,000 per year per MW for 15 years is too low to justify building new gas CCGT capacity, unless the operator is willing to take a substantial risk on operating hours and the energy margin.
22. The Department of Energy and Climate Change has just published an analysis of the effects of policies on energy bills. The estimates for 2020 imply that gross capacity market payments will amount to £3.75 per MWh or about £1.25 billion on a basis that is consistent with my analysis. After allowing for payments to existing generators, it seems that DECC’s estimates for the cost of supporting new backup generation to provide resilience are similar to or even higher than my estimates.
23. The payments made in respect of capacity market contracts will be a pure addition to charges for balancing services and network costs. Because of the way in which half-hourly system prices are set in the market, there is no reason to expect that the refurbishment or construction of generating plants contracted through the capacity market will have a significant impact on future system prices. Neither will this affect the increase in price volatility discussed earlier as the analysis allows for the entry of new backup capacity that will set the system price when wind generation is low.
Conclusion 24. The key to understanding the problems of resilience in the GB electricity market due
to the addition of a large amount of renewable capacity to the generating mix does not lie in the risk of power cuts. That may happen but it will be due to bad luck and/or poor management. The real issue is that the costs of meeting electricity demand will be progressively but very substantially increased. The level of subsidies required to offset the high costs of renewable generation are well documented. What is less well understood are the marginal costs of balancing the system,
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providing sufficient backup through the capacity market and hedging the increase in price volatility caused by the variability in renewable output.
25. My estimates of the increase in balancing costs and payments for new backup capacity amount to about £1.7 billion (at 2013-14 prices) per year. The additional cost of hedging is much less certain, because companies can choose to offset risks between their generation and supply businesses or simply absorb the risks through larger capital buffers and/or a higher cost of capital. As an illustrative calculation, if 50% of electricity consumption were hedged at an extra cost of £20 per MWh the cost of an increase in price volatility would amount to £3.4 billion per year. Even if these payments are not actually made, this is an economic cost which must be met out of a higher return on capital or in other ways.
26. By 2020-21 the total cost of market interventions to promote renewables will amount to about £12.5 billion per year at 2013-14 prices - £7.4 billion for feed-in tariffs, ROCs and CfDs under the Levy Control Framework plus £5.1 billion for the items discussed above. To put this total in context, the market value of electricity supplied in the UK in 2013-14 at the system price was about £17.9 billion. As the cost of these measures are recovered from electricity users, these subsidies and resilience costs will increase the effective cost of wholesale electricity by about 70%. This takes no account of the additional expenditures planned to strengthen the transmission grid or distribution networks.
27. There are widely differing views about whether support for intermittent renewables is a cost-effective way of reducing carbon emissions or the UK’s vulnerability to price shocks from international energy markets. What cannot be disputed is that the costs of such support are large. They tend to be underestimated in official publications which focus on the direct costs covered by the Levy Control Framework and neglect the indirect costs incurred to ensure the resilience of the electricity system.
8 November 2014
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Professor Gordon Hughes, University of Edinburgh, Renewable Energy Association and Professor Richard Green, Imperial College London – Oral evidence (QQ 80-90) Transcript to be found under Renewable Energy Association
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IESIS – Written evidence (REI0013) Author: Iain A MacLeod, President 1. Introduction While Ofgem produces an annual report111 on Electricity Capacity Assessment for the next 5 winters, as far as we know, reliable information about the resilience of the GB electricity infrastructure to peaks in demand and sudden shocks is not available on a planning timescale (20+ years). The Call for Evidence notes that measures are being taken to improve capacity margins. While capacity margin is an indicator of resilience, we recommend that the main metric for characterising resilience is the probability of generation being unable to meet demand. This probability is then assessed against an agreed Standard – see Section 3. Meeting an agreed Standard should be a non-negotiable requirement in electricity planning. All proposals made for the Electricity System should meet the Standard. Use of such a standard should be considered as best practice for assessment of resilience. The basic technology for it is well developed and has been successfully tested. The calculation of the probability for security of supply should take account of all risks: risk of failure and non-availability of plant, risk that fuel will not be available, intermittency of renewable input, etc. 2. North American experience with resilience of the electricity system In 1968, in response particularly to an extensive blackout in 1965 that had repercussions over the whole of the NE of North America, the National Electric Reliability Council (NERC) was established. This was based on voluntary agreements about standards. Further blackouts occurred, and in 2007 the NERC Standards became legally enforceable. Britain does have some enforceable reliability measures, but is a long way behind North America in putting a comprehensive set in place. It is recommended that the North American experience be used to inform the creation of a system that will seek to ensure resilience/reliability of the GB electricity system. 3. The GB situation The National Grid Company(NGC) works, in a highly effective manner, with the plant and transmission available to seek to achieve security of supply. It has however no responsibility for what plant will be available in the future and does not assess the reliability of the system on a planning timescale. OFGEM’ s role is market regulation, not system planning. No body has responsibility even for assessing future security of supply for the GB system. Appendix 1 gives the results of a recent assessment of the risk to Security of Supply based on comparison against a Standard as outlined in Section 1 of this response. This is based on the methodology used pre-privatisation and represents an alternative approach to that used for Reference 1.
111 Ofgem Electricity Capacity Assessment Report 2014 https://www.ofgem.gov.uk/publications-and-updates/electricity-capacity-assessment-2014.
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The graph in the Appendix shows the predicted risks to Security of Supply up to 2036 and gives a direct comparison with the pre-privatisation Standard of 4% i.e. that in no more then 4 winters in 100 years would we fail to meet the System Maximum Demand . 4. Needed action (Note that we do not make a distinction between ‘resilient’ and ‘reliable’. They both refer to a state of acceptable risk of unsatisfactory outcomes) Having a reliable electricity system is of prime importance to the nation. Both logic (that market arrangements do not address security of supply) and experience (e.g. the North American experience) lead to the conclusion that a national body is needed to seek to ensure that we do have a reliable electricity system. In the absence of such body the risk that we will suffer blackouts similar to the North American experience is high. Good technology exists to reduce this risk to an acceptable level. It makes no sense to avoid using it. The estimates of risk to Security of Supply should be produced from a system model112 that would also take account of cost and other factors. Using such a model, the efficacy of various strategies for reducing the Risk (e.g. demand-side measures, use of standby oil-fired generators, putting mothballed generators back in to service, etc.) would be assessed leading to well informed decisions being made. 18 September 2014 References 1. Mackenzie I Bulk Electricity Reliability in North America
http://www.iesisenergy.org/sofs/Electricity-reliability-NAmerica.pdf 2. National Grid Future Energy Scenarios http://www2.nationalgrid.com/uk/industry-
information/future-of-energy/future-energy-scenarios/ 2014 Appendix 1 Estimates of Risk to Security of Supply Figure 1 shows a graph of estimates of Risk to Security of Supply for the GB Electricity System from now until 2036. The graph shows that the Risk increases from the 8% actual in the 2013/14 winter to nearly 40% by the early 2020s as compared with the 4% Standard. The 4% Standard infers that one would expect a failure to meet demand once every 25 years. With the 40% risk, 2 failures every 5 years would be expected. These estimates uses a lower contribution from wind than used in reference 1. The graph indicates increasingly unsatisfactory levels of risk to Security of Supply up to 2023. This demonstrates the urgent need for analysis of this type based on the most reliable data for all generation in the system and the use of the most advanced statistical methods that are available. The spreadsheet use to do the calculations can be viewed at: http://iesisenergy.org/sofs/Estimates-of-SofS-for-GB-system.xlsx
112 Gibson C M and MacLeod I A Engineering the GB Electricity System IESIS Journal of Engineering Vol.154 7-12 2014 Available at: http://www.iesisenergy.org/sofs/Engineering-GB-Electricity-System.pdf.
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Figure 1 Estimates of the Risk to Security of Supply for the GB System up to 2035/36
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The Institution of Engineering and Technology (IET) – Written evidence (REI0032) EXECUTIVE SUMMARY 1. The UK electricity system has enjoyed high levels of resilience historically, and remains resilient today, but things are changing fast that pose risks to resilience in the short, medium and long term. 2. Resilience is not achieved by picking off and solving individual problems but results from the inter-play of all the multiple inter-related components and factors that form the whole electricity system. The lessons that can be learnt from the last period when electricity resilience was an issue, the 3 day week in the 1970s, are of limited value in the current context because both the underlying issues and the opportunities for resolving them are significantly more diverse. 3. The Government has taken steps to address the short term supply issues through electricity market reform (EMR), but the measures have to work if we are to retain good resilience, and some of the risks are outside direct government control, (for example willingness of investors to invest, and State Aid clearance on new nuclear projects). In the short term, GB will be exposed to lower than historic plant margins from the coming winter until plant procured under EMR provides capacity from 2018. 4. More significant for the medium term (and to a degree the short term) are the transformational changes to the electricity system as a consequence of decarbonisation. These include the introduction of large amounts of self-dispatching renewable generation, the potential electrification of much of transport and space heating, and the rise of the smart consumer and smart home. These, combined with the need to make power networks fit for this new world, vastly increase complexity and require a level of engineering coordination and integration that the current industry structure and market regime does not provide. In turn this increased complexity presents potentially substantially increased vulnerability to cyber threats. 5. The IET recommends the establishment of a System Architect function in the near future to allow these challenges to be addressed effectively. 6. A System Architect function will allow coherent engineering solutions to be developed and implemented such that resilience is ensured, whilst also optimising costs to consumers as the transformation implied by decarbonisation is delivered. RESPONSES TO QUESTIONS Short term (to 2020) QUESTION 1: How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base?
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7. We outline below the broad range of aspects which need to be considered in order to answer this question. Capacity margin 8. The GB electricity system is currently able to meet reasonably foreseeable consumer demand peaks with a margin to allow some generation to be out of service for maintenance or through breakdowns. Since privatisation, for a variety of reasons, the GB electricity system has enjoyed a generous margin of capacity over peak demand, but this has been eroded in recent years as the rate of plant closures has been faster than the rate of new dispatchable113 capacity being built. 9. The picture has become more complex since large amounts of variable renewable energy capacity (wind and solar) has been added in recent years, because whilst this provides substantial amounts of energy over the course of a year, its contribution to dependable capacity at times of peak demand is relatively limited. 10. If generation is marginally insufficient to meet demand (something not seen in GB since the 1960s), National Grid, as the national electricity system operator, has options such as contracting for peak demand reduction from industrial users, and managed voltage reductions, to allow supplies to be maintained to all consumers. Whilst these measures are rational engineering and commercial responses to managing supply and demand, it is of course possible that they might attract adverse press comment should they be implemented. It is noteworthy that of all the many large power projects currently in construction, only the new gas fired plant at Carrington will give a high level of additional capacity reliability at peak demand, and this will be 1 GW, compared to the 7 GW of coal and oil fired plant closed in the last two years. 11. The power system in Northern Ireland is essentially independent from GB, and has in recent years been fully integrated with that in the Republic of Ireland, something which will have generally increased its resilience. However the overall Irish system is deploying large amounts of variable renewable generation, and will tend to experience the same issues as the GB system. System Stability 12. New sources of generation such as wind and solar also have lower levels of inertia than the conventional power stations they displace. This means they transfer less energy to the system under fault conditions or sudden losses of generation, resulting in more rapid falls in system frequency and more severe voltage dips. This can in turn cause the growing fleet of small generators embedded in distribution networks to disconnect thereby exacerbating the problem. The industry is aware of this problem and is developing solutions, notably through the Grid Code and Distribution Code Review Panels. Fuel supply
113 Dispatchable capacity means capacity whose output can be set at will (subject to technical limitations), rather than capacity whose output is determined by uncontrollable factors such as local wind speed.
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13. Both the GB and all Ireland electricity systems enjoy a mix of fuel sources and are thus relatively resilient to fuel supply shocks, though there remains exposure to fuel price volatility, particularly gas. Other ‘sudden shock’ events 14. Other “sudden shock” risks, such as type faults on equipment (i.e. faults in design or manufacture that will affect batches of, or potentially all, equipment of that type), severe weather and/or terrorist attacks on key infrastructure such as major transmission lines are managed through a diversified plant base, and a meshed transmission network with high levels of attention given to operational resilience. Thus the impacts of such events would tend generally to be limited in their geographic spread. However the risk does remain that a concerted successful attack by an efficient organisation informed by deep knowledge of the power system, on a number of unprotected and geographically dispersed assets (transmission line towers or possibly major substations) simultaneously could cause a widespread if temporary disruption to power supplies. 15. Distribution systems are less resilient to extreme weather and, as has been seen recently, localised damage can occur that results in groups of consumers being off supply for some days, particularly in rural areas. This has been the subject of Parliamentary inquiry early in 2014, and measures are being put in place to improve emergency response arrangements. Steps have been taken by the distribution companies to increase resilience to severe weather events, including flood mitigation, use of insulated overhead line conductors, rebuilding lines to a heavier construction specification, increasing lightning surge withstand capability, and automated switching to isolate faults and restore supplies. Resilience could be further improved by even greater levels of investment (with resulting increases in consumer prices which Ofgem’s consumer surveys have indicated would not be supported) but, whilst such events are highly inconvenient for those consumers affected, they do not threaten the integrity of the electricity system as a whole. Interdependencies 16. The electricity system is dependent on the successful operation of other infrastructures including gas transmission, telecommunications, highways (so staff can reach sites to repair faults), railways (for coal transport). Major outages of these systems could impact electricity system resilience. Fortunately the UK enjoys good resilience amongst these individual systems at present, though interdependency with the communication system involving a potential cascade of failure needs to be planned for. 17. The use of cell phones to co-ordinate maintenance by some electricity companies creates a critical inter-dependency as service would be lost from the current cellphone networks in a widespread power outage. (Whilst macro cells do have backup power they would be swamped when the lower tiers of cells with minimal or no backup shut down). Clearly loss of terrestrial communications could severely hamper network recovery. However, back-up systems are available; for example larger distribution substations are equipped with PSTN land lines and Satellite or UHF based SCADA (supervisory control and data acquisition) systems which have voice communications capability, either of which would enable repair teams to maintain voice communications with control rooms and dispatch centres in emergency conditions. The current procurement for a new “blue light”
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emergency services network could result in one or more of the existing cellular networks being hardened against power failure of reasonable (24 to 72 hour) duration. This could represent a major opportunity to build a firebreak in the interdependency between power and communications. Conclusion 18. In conclusion, it is possible today to say that the current UK electricity infrastructure is highly resilient. However this picture is changing quite rapidly – in the short term as plant closes and demand begins to recover following the recession, and long term as the UK moves further into its energy transformation. This will create new resilience challenges which are discussed further in our response to subsequent questions. The evidence base 19. In terms of the evidence base for the above comments: precisely because we have yet to experience the scale of the impact of peaks in consumer demand and sudden shocks to the system that we predict, our evidence is necessarily based on modelling and analyses. National Grid’s Electricity Ten Year Statement describes some of the outputs of such modelling (for example system strength and system inertia and their respective future impact on system stability, power quality and electrical power system protection). These and other issues will be subject to more regular and detailed studies under National Grid’s new System Operability Framework. Meanwhile, the Smart Grid Forum has undertaken, and is continuing to undertake through its various workstreams, studies to evaluate the impact of future electricity system challenges and their potential solutions. QUESTION 2: What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’? 20. In the short term (to 2020), the main challenges to system resilience are:
(a) Capacity and its technical characteristics:
The risk of the market not bringing forward sufficient new dispatchable generating capacity to replace older capacity being retired. As well as coal fired power stations, recent retirements have included significant numbers of gas fired stations, caused by low coal and carbon prices limiting their operation, and their owners seeing the inflexibility of many 1990s era plants as inappropriate to future requirements;
The intention is that the EMR capacity mechanism along with new measures proposed by the electricity system operator such as Supplementary Balancing Reserve and Demand Side Balancing Reserve will reduce the risk of plant capacity shortfalls. Supplementary Balancing Reserve is largely dependent on sufficient existing large plant being contracted to remain connected rather than be shut down by its owners, as this timescale is insufficient to allow new plant to be consented and built on a large scale;
A reduction in fuel diversity caused by the closure of many coal fired power stations, giving greater exposure to gas price volatility for dispatchable capacity;
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The dynamic response of existing dispatchable capacity not being adequate for the very different duties it will be called upon to perform compared to its design duty;
Falling system strength and inertia due to new generation types, which will make it more difficult to maintain system stability at times of system stress;
A possible lack of willingness by the private sector to invest large amounts in what has become a politically “hot” sector of the economy;
The extent to which the operation of the EMR Capacity Mechanism might hamper the wider use of demand response to manage peaks (since contracting under the Capacity Mechanism precludes the option to supply reserve services from the same source of demand response).
(b) More variable generation and changing demand:
The possible return of significant year on year growth in electricity demand as the economic recovery gathers pace;
The increasing deployment of variable renewable generation to much more than the current capacity;
The possibility of new sources of demand such as electric vehicle charging increasing very quickly should consumer demand for electric cars take off;
The possible emergence of large amounts of load that is controlled in response to variable tariff signals from energy suppliers, including the potential entry of major consumer brands such as Google or Apple into this market, with corresponding high consumer take-up;
Limits of distribution network capacity being reached locally, especially in cities, with solutions taking time to implement and hence potentially acting as a brake on economic development;
The beginnings of sophisticated but non-integrated control responses to all these within networks;
The implications of the UK leaving the EU in the event of this being the referendum outcome. There is no inherent reason why this should be problematic but this would depend very much on how collaboratively any separation was handled.
(c) Emerging cyber security issues:
A further concern is that the future system will be much more dynamic and reliant on fast communication and data analysis to ensure technical security and stability. This will reduce the feasibility of manual operation and increase dependence on automation, further exacerbating the potential consequences of cyber attack. For further discussion of Cyber Security issues see paragraphs 38 - 43.
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21. Most of these challenges are new and have not had to be addressed before. Whilst the challenges are understood and solutions are being developed, these issues have potential impacts on the whole system which, by definition, are less well understood. The UK, in common with some other countries, is moving into areas of operation where we have little practical experience to guide us. Measures being taken to improve resilience of the UK’s electricity system 22. A number of actions have been taken by government and industry to mitigate the challenges and to develop an increased understanding of the way forward. For example:
The current Government’s Electricity Market Reform includes capacity auctions, which if successful should result in investors gaining the certainty needed to build new dispatchable generation capacity and/or develop demand response and energy storage solutions. Future system resilience is critically dependent on these auctions succeeding.
The increasing availability of interconnectors between GB and other countries, and to improve connectivity between Scotland and England/Wales. Planned new interconnectors include NEMO (providing a connection to Belgium), and a further GB-France link. It should be noted that because GB is an island, all interconnectors between it and other countries use highly resilient DC technology, rather than conventional AC. This has the benefit of greatly reducing the risk of the cascade failures experienced in the USA and mainland Europe.
Ofgem and the industry have been innovating through the Innovation Funding Incentive (IFI), Low Carbon Network Fund (LCNF), and Network Innovation Allowance and Competition (NIA/NIC) to explore issues around variable generation and demand on networks and new forms of demand such as electricity vehicle charging and electric heat pumps. However in our view there are a number of as yet unexplored areas in this work. This is primarily due to the focus of LCNF having hitherto been confined to distribution networks whilst the NIA/NIC has been confined the transmission networks. We do not yet have an integrated whole system approach to dealing with these emerging challenges though, from 2015, the Network Innovation Allowance and Competition will allow both DNOs and TNOs to collaborate (or compete) for funding and hence help address this imbalance. The need for such an integrated approach has been the focus for the IET Power Networks Joint Vision activity.
23. The IET has concluded that there needs to be more effective engineering systems integration across the electricity system as it embraces these major changes, and has recommended the establishment of a System Architect function to ensure this is delivered. It is not possible to say with certainty when the issues highlighted in this section may all become real, and in some cases this could be after 2020. However given the importance of a resilient electricity supply to social and economic well-being, we believe it to be important that effective systems engineering is undertaken sooner rather than later. Adopting a reactive rather than proactive strategy is likely to lead to inefficient recovery actions and suboptimal investment, and may in any case lead to actual system failures. Comprehensive analysis of the impacts on the electricity system of credible future scenarios should minimise
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the risk of either stranded or inadequate investment, ensuring timely and optimised investment to deliver an adequate system at the most economic cost. QUESTION 3: How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? 24. At present there is no single authority responsible for electricity resilience, and little use of consistent metrics to describe it.
The market is currently left to provide adequate generation capacity. This will change when National Grid runs the first capacity auction mandated by DECC later this year, for capacity to be delivered in 2018/19.
National Grid is responsible for the safe and secure operation of the GB transmission system within is licence conditions (determined by Ofgem).
The Transmission and Distribution Network Operators are each responsible for safe and secure operation of the system within their licensed areas according to their licence conditions (vis. to develop and maintain an efficient, co-ordinated and economical system of electricity transmission and distribution).
25. Hence:
DECC and Ofgem come to a technical conclusion over how much capacity should be purchased at a capacity auction, though this does not deal with the situation prior to 2018, which is in the hands of the market;
National Grid procures response and reserve services (such as frequency response, fast reserve, short-term operating reserve, black start capability, voltage and reactive support) and potentially in future other systems services such as inertia via tender, to the extent these are beyond the Grid Code requirements incumbent on generators;
National Grid works within defined security standards for its transmission system, which it reviews from time to time;
DNOs work within defined security standards and are also incentivised financially by Ofgem to meet targets for guaranteed standards of service, customer minutes lost and customer interruptions;
Both transmission and distribution network operators also have to submit full business plans to Ofgem and report annually on outcomes. Network investments are justified to Ofgem on a range of grounds including the various aspects of resilience, including issues such as the impact of flooding resulting from climate change. However the regulatory regime requires companies to demonstrate that all investment is fully justified and this can limit the scope for investment ahead of proven need, especially where there is a risk of the investment becoming stranded.
26. With the arguable exception of the market not signalling a need for new capacity (up to 2018), it will be seen that there are established arrangements in place to build the business cases to deal with many resilience problems, with the arguable exception of cyber security (see our later commentary on this issue). However resilience problems that cross
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company boundaries, or emerge because of the side effects of the very major changes now occurring to our electricity system as it and the wider energy system decarbonise, are not well captured by the current arrangements – hence the IET’s recommendation for a system architect function. There is also no commonly agreed metric for resilience, meaning investment for resilience overall can be difficult to justify. QUESTION 4: What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? 27. The government’s existing policies are designed to ensure the provision of adequate generating capacity (from 2018/9), and (via existing regulatory arrangements governed by Ofgem) the resilience of the transmission and distribution infrastructure against known challenges. They are also effective in fostering innovation in networks on a trial basis. 28. However existing policies do not take account of the scale of the potential impact of decarbonising on the electricity system, combined with consumer market responses to the desire to manage energy well, and potentially to manage supply security locally in some cases. This is by far the largest change the industry will have had to manage in its history. 29. These changes will not produce a resilient and affordable system if they are each treated as bolt-ons to the existing system, and are likely to produce unexpected and costly side effects, constraints to future activity, and risks to stability and hence resilience. Many of the issues to be addressed are currently unquantified, and we cannot be certain that we yet have all the modelling tools necessary to explore them analytically. (See question 7) 30. An electric power system is a complex engineering system, and needs to be treated as such. It is particularly demanding because it is an existing system with inherent legacy characteristics (rather than a new system designed at the outset to cope with the challenges we now foresee) and hence requires us to develop an adaptation strategy that will assure continued security of supplies whilst at the same time undergoing a major technical and operational transformation. 31. It is possible, even likely, that some of the impacts of these changes will not manifest themselves until after 2020; however the costs of putting right the consequences of bad decisions made prior to 2020 as a result of poor engineering systems integration could be very high. 32. The sooner the recommended System Architect function is established, the less severe are the problems likely to be, and the wider the options for managing them. At best, failure to act could cause inefficient investment in short term solutions, make government policy objectives more difficult to achieve, and cause widespread public frustration. At worst, it could ultimately threaten the integrity and security of the whole power system. 33. Prior to 2018, the capacity situation needs to remain under constant review, something Ofgem does on an annual basis. National Grid has plans and arrangements in place to procure capacity and to take other measures if needed, but the rate of plant
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closures needs to be monitored carefully. Unexpected coincidences of technical issues on what are now very old plant can quickly make a big difference. A very recent example is new incidences of cracking on existing nuclear plant causing all four reactors of similar design to be shut down for inspection and possible rectification, at roughly the same time as unrelated fires shutting two coal fired units, with a total unexpected capacity loss of over 2 GW (compared to a winter transmission system peak demand around 57 GW). QUESTION 5: Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure? 34. Yes. We are likely to see sufficient pilot schemes and early commercial deployment of most of the key technologies for decarbonisation within the next 6 years to gain insight into emergent issues. These are likely to include:
Electric and plug-in hybrid vehicle deployment
Variable renewables at very large scale
Heat pumps
Smart homes and dynamic tariffs, depending on rate of take-up
Smarter grids at distribution level
Ultra flexible operation of CCGT plant
Carbon capture and storage (if deployed in time)
Community level integrated energy schemes
Evidence of impact of the smart meter rollout programme
35. The lead times in electricity infrastructure investment can be long, especially for major capital programmes such as large power stations, or for solutions to be deployed widely amongst consumers or on distribution networks. However significant externally driven changes, especially those in the hands of consumers, can take place very quickly. Examples of this would be the speed of market penetration of smart phones, or the rapid uptake of solar photovoltaic panels. One can imagine that the impact of electric vehicles or smart homes and dynamic tariffs could grow very fast if these were to catch on amongst consumers. 36. We will also learn a great deal about operating the system under low margin conditions. The learning will depend on circumstances, but will advance our understanding of how much contingency really exists in the system, or can be contracted, and how to use it. The evolution of demand will also be interesting, especially whether the positive effects of economic growth and take-up of electric vehicles outweigh reductions from increased energy efficiency and declines in energy intensive manufacturing. 37. This means an early need for effective engineering systems integration to ensure policy decisions are subject to an “engineering integrity” test and are able to respond quickly and appropriately to emergent issues. National Grid’s new System Operability Framework
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will support this by providing deeper insights into the technical challenges arising from new types of generation and demand. ADDITIONAL QUESTION: What are the main IT and cyber issues affecting resilience and how should they be mitigated? 38. Many aspects of the UK’s electricity system depend on computer-based systems. It has been reported that foreign states and others have been detected probing for vulnerabilities in critical infrastructure, so it must be assumed that the UK is also a potential target. 39. Legacy systems were introduced before cybersecurity was recognised as a Tier One national threat. 40. The roll-out of Smart Meters will increase the complexity of the electricity system and the IET has expressed concerns that the design and implementation of the Smart Metering security architecture has not followed best practice for cybersecurity. 41. The costs and benefits of best practice cybersecurity have not been addressed in detail in any DECC documents that the IET has reviewed. The suppliers to the electricity industry are not as familiar with high integrity software development methods as, for example, suppliers to the avionics or nuclear power industries and it seems that this inhibits DECC from requiring the use of modern software assurance methods, for example in the smart metering system. 42. Focused attention needs to be given to assuring the cybersecurity of the specification, design and implementation of critical systems, using mathematically formal specifications and proofs of compliance supported by model-based testing. 43. IT security should be an intrinsic consideration in all energy infrastructure development. One of the roles of the System Architect function recommended by the IET would be to ensure that IT security is at the heart of technical specification of an integrated system. Medium term (to 2030) QUESTION 6: What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience? 44. Between 2020 and 2030 we would expect to see an evolution of the changes set in place before 2020, bringing:
renewables on an even greater scale
the probability of a profound change in how consumers consume, and
the possibility of massive increases in electricity demand in the event that most transport and space heating becomes electrified.
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45. These could be offset to some degree if real progress is made on policies to improve energy efficiency, and change consumer behaviour to either use less energy, or shift more of their energy consumption to times when the system is less stressed. However, the scale of the potential change makes it critically important to gain clarity of likely outcomes sooner rather than later. 46. There could also be a continuing increase in climate volatility, with more flooding, drought and extremes of temperature putting new stresses on electrical equipment and infrastructure generally. 47. This aspect of supply security is receiving particular attention in the USA where recent ‘super storms’ resulted in severe disruption to the electricity system. A potential solution being explored is the concept of ‘micro-grids’, where advanced smart grid techniques are deployed to enable buildings, campuses or communities to detach from the national power system and operate as ‘power islands’ for a period of time. Implementation of this approach has to overcome demanding technical challenges and, should it be contemplated at some stage for enhancing GB supply security, would require a clear long-term migration plan and close integration of technical, commercial and regulatory aspects. 48. Whilst the UK doesn't currently tend to suffer the extreme wind storm conditions that cause severe damage to transmission systems, the position might change in the longer term due to climate change. Moreover, although relatively rare, storms leading to severe ice build-up on overhead conductors have in the past led to the failure of steel pylons. Under the vast majority of severe wind conditions, including hurricanes, the UK transmission and high voltage distribution systems are generally restored rapidly (including through automated switching). By contrast it is generally damage to the rural low voltage systems that causes extended supply interruptions. Rural micro-grids might be equally susceptible to such storm damage on their local networks, and with possibly fewer resources to call on at times of emergency to effect repairs. Micro-grids would, however, have the benefit of being able to continue operation in the event of a serious loss of generation or transmission capacity due to storm damage or other causes including for example terrorist activity. 49. At a more detailed level, changes to network planning and installation practice to accommodate flood risk, as well as remedial measures, are still ongoing, for example, ensuring that substations are adequately protected and that there is ease of access to switching and isolation points on networks to allow work to begin before waters subside. 50. There are likely to be new emergent phenomena as the electricity system is taken even further beyond current (2014) knowledge, and we will need to have the academic and corporate research infrastructure to find the necessary solutions. Many of these challenges are global so this needs to be seen in that context. This has implications in the shorter term for skills development and academic capacity – a teenager choosing STEM options in 2014 could be a useful young researcher in 2024, and a good 2014 engineering graduate choosing an engineering career (say over one in the City) could be leading an industrial research unit in 2030.
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51. The need to be “match fit” to address these challenges again points to the urgency of establishing good arrangements for ensuring effective systems engineering of the electricity system sooner rather than later. QUESTION 7: What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? 52. Modelling provides insights into a range of pathways towards a resilient and low carbon electricity supply by 2030, and this will be more affordable provided sensible systems engineering decisions are taken as to where to prioritise efforts. A range of models are used, typically including sophisticated economic and financial models, whole energy system models, complex iterative simulation models, and a range of technical models relating to the engineering performance of the electricity system. 53. The IET’s focus is on the engineering issues of future system resilience, and hence on the specialist models that allow the dynamic performance of the electricity system to be simulated. The present system is well understood through simulation using mature modelling packages which enable parameters such as: the operation of power stations, power-flows, fault levels, transient and voltage stability, electromagnetic transients, power quality, harmonic distortion, and other important aspects of power system operation to be mathematically modelled. In looking at the energy transformation going forward it will be important not to lose the lessons from past experience embodied in these models and in the experience of engineers in the industry. 54. However as we proceed through the UK’s energy transformation we are faced with new dynamic variables which existing models were not designed to address, as well as new uncertainties that require existing models to be used in new and complex ways. The IET is currently undertaking work for the Council for Science and Technology to explore the modelling capability and identify any gaps. This study will report in December 2014. 55. The study will comment on the current modelling landscape (capability) and outlook (i.e. the need for new or improved models with common underlying datasets). 56. National Grid’s new System Operability Framework (SOF) will provide a framework to enable these modelling needs to be co-ordinated and prioritised at the transmission system level. However, many aspects of the SOF will have a direct bearing on the design and operation of electricity distribution networks as well as transmission and hence co-ordination across both systems will be essential. QUESTION 8: What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? 57. We would argue first for an effective System Architect Role, as stated in our response to a number of your questions. This will be essential in limiting the costs of what will be an inevitably expensive transition to a low carbon resilient electricity infrastructure.
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58. In addition we need to move over time to integrating the commercial arrangements for variable renewables (i.e. initially wind and solar but potentially wave and tidal technologies in the longer term) into the wider electricity market. Variable renewables need to be valued for their zero or low marginal cost of low carbon energy, and for any capacity contribution they make. We would suggest they are also charged equitably for system costs incurred for system services provided by other generators and service providers. We need to make similar arrangements to fully integrate and value demand participation. This is a challenging issue with implications for future EU directives on energy; however it is one faced by a range of EU member states. 59. We need also to work harder to deliver greater energy efficiency through a range of measures. This can be key to affordability. Energy efficiency is usually highly cost-effective but a wide range of barriers exist to its systematic adoption. 60. All this depends ultimately on engaged consumers. Government and industry need to continue to work to engage people in their personal energy economy, and both the government and the industry need to act to rebuild lost trust. QUESTION 9: Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? 61. Most of the technologies required exist but need the experience of deployment at scale in world markets to evolve in function and efficiency and reduce in cost. This comment applies for everything from nuclear power stations to home energy management. It is important that the UK must not develop UK-only standards and practices if it is to benefit from innovation in world markets, and from export opportunities for UK providers. 62. A wide range of new equipment technologies is in development which will create more options for electricity system management over and above those in use today, but will not individually be game changers. Examples of are shown in Table 1. Table 1: New power system management technologies currently in development
NEW TECHNOLOGY INFRASTRUCTURE RESILIENCE BENEFIT
Automated and/or autonomous self-reconfiguring networks
Rapid post-fault supply restoration
Dynamic real time thermal equipment ratings Releases additional capacity from conventional assets
Electrical energy storage in conjunction with power electronic convertors at a range of durations and for a range of scales. (For further explanation see the IET Factfile on
Can serve multiple needs including network capacity support, operating reserve and frequency response.
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Electricity Storage) http://www.theiet.org/factfiles/energy/energy-storage-page.cfm
Power electronics applications such as static VAR compensators and statcoms
Improved voltage control and efficiency of network power flows
Advanced network monitoring and control systems embracing state estimation and contingency management computation
Assurance of network capability under an increasingly diverse range of credible power flows
Meshed networks employing sophisticated power-flow management techniques, including power electronics devices
Higher network utilisation and/or reduced losses
Adaptive protection systems Ensure the continued safe operation of transmission and distribution networks under predicted future dynamic changes in system strength (fault levels)
Active management systems which can interface with generator control systems and consumers’ energy management systems to dispatch or curtail export and demand
Manage power flows on networks without investment in additional capacity
Phase shifting transformer and power electronics based “soft” open points
Improved load sharing across networks
Series compensators and thyristor switched capacitors
Enhance capacity headroom of transmission networks by optimising voltage levels and improving efficiency of power flows
Voltage source converters interfacing between ac and dc transmission systems
Promises a number of technical and economic benefits over traditional current source technology for connecting dc interconnectors to the GB ac system
Fault current limiters Enhance capacity headroom in distribution networks to allow additional generation to be connected
Improved designs and materials such as amorphous steel-core transformers
Reduced losses
A wide range of advanced diagnostic techniques (including ultra-sound, infra-red, partial discharge detection, acoustic signature, dissolved gas analysis)
Allow critical asset health indicators to be monitored leading to reduced risk of in-service failure or premature replacement
The exploitation of “synthetic inertia” capability inherent in the speed control system for some generator types used with wind turbines
Help mitigate the overall reducing level of system inertia
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Smart metering equipment meeting the requirements of the UK technical specification SMETS2 which will include data transfer via a centrally managed communications system
Provide valuable information on low voltage network power flows and voltage levels, enable better control of voltage to reduce losses, alert network operators to power outages and power quality problems, and also enable the development and use of dynamic tariffs
63. Whilst these technologies each have the potential to make a valuable contribution to future system resilience, this will depend critically on selective application and effective integration, and establishing the necessary business processes that will ensure effective transition from demonstration to business as usual. The engineering integration, even of established technologies into a system with novel topologies and architectures is a non-trivial task that carries risk, and hence will require an engineering systems integration approach (see question 12). 64. Future R&D funding will need to focus on integration of the above (and other) technologies by deploying solutions at scale. 65. A further potential game changer is a much stronger role for community energy rather than large remote energy providers. Community energy is often seen as part of a wider strategy around smart communities, integrating a wide range of consumer’s needs to meet as much of them as possible locally. Enablers for smart communities include the big data and communications revolutions we see underway today. The extensive deployment of community energy infrastructure could potentially reduce the need for further capacity investment in transmission networks and the higher voltage parts of distribution networks, such that their role evolves increasingly from providing bulk supply to provision of balancing capacity. In principle, this could enhance system resilience, provided the community energy network is engineered such that it can interact with its local power system when both are operating normally, but continue to operate when disconnected from the wider electricity distribution system (balancing supply and demand within the community). This would occur when supplies from the wider system are disrupted under system fault conditions. However, further work is needed to understand the costs and benefits involved, given the sophisticated network management systems that would be required. The Smart Grid Forum is actively considering any regulatory or commercial barriers that might require attention to promote the economic development of community energy schemes. 66. A further technology under development using largely proven elements is tidal lagoons. The UK has a large potential resource (>10 GW), and costs and environmental impacts would appear to be lower than for large tidal barrage schemes. DECC is currently taking a considerable interest in this technology. QUESTION 10: Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
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67. The electricity sector is a worldwide market with a global supply and innovation base. The UK has historically proved an attractive destination for inward investment, as well as for innovative start-up companies. There is plenty of room for UK innovation, export, employment and economic growth, and this is being seen already, for example in Low Carbon Innovation Fund projects, many of which have engaged UK SMEs. 68. A pragmatic view needs to be taken of where support to innovation has a realistic chance to succeed in developing new UK export industries, and it will be key that barriers are not introduced by specifying requirements and solutions unique to the UK that are not aligned to the direction of travel in other world markets. 69. All new technologies carry risk in development, and may not evolve into competitive commercial propositions, so it is wise not to limit technology choices unduly. We would recommend an open and diverse approach to technology, using the energy transition to create an environment to welcome innovation. 70. The Energy Systems Catapult, to be launched in April 2015, can play a key role here in catalysing the development and commercialisation of promising new technologies. QUESTION 11: Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects? 71. As mentioned above, Ofgem’s initiative in introducing first the Innovation Funding Incentive (IFI) in 2005 and subsequently the Low Carbon Network Fund in 2010 (to be superseded by the Network Innovation Allowance and Competition) have provided a strong incentive for transmission and distribution network operators to re-engage in effective research, development and deployment. All network operators have responded positively to the incentive and this has led to the development of many of the technologies referred to in Q10 above. 72. The results of this research is widely and effectively disseminated through regular dissemination events, a smart grid web portal (which is now under further development) and a highly regarded annual conference. 73. Network Operators have also demonstrated that this research is already leading to significant network investment efficiencies, as demonstrated in their Business Plans for the regulatory periods covered by Ofgem’s RIIO ET1 and ED1, and are now beginning to systematically adopt these new solutions as business as usual. However, there is much more to be done before we can be confident that we have the capability to effectively integrate these solutions at scale. 74. Going forward, the new Energy Systems Catapult should be effective in ‘bringing-on’ new technologies, not only for the benefit of UK consumption but also as potential employment growth and export opportunities. 75. The System Architect role would be supported by such on-going effective RD&D and would be in a strong position to leverage the benefits of integrated deployment.
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QUESTION 12: Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? 76. We believe the current approach, which is a mix of market led, regulator led and government led, is missing the key element of engineering systems integration. This has been less important historically. The system was changing only slowly and knowledge gained over the last 100 years was enshrined in the industry codes everybody follows. 77. However we are now in the early stages of a period of profound change. We are not yet in a position to forecast where this will ultimately lead or predict all the problems that will emerge. In the absence of a systems integration approach there would be a serious risk of investing heavily in assets that could become stranded, or of losing resilience through poor systems integration. There will be a greatly increased need for new engineering skills in the industry, and greater demands on the engineering competence of companies involved. 78. The IET recommends the establishment of a System Architect role in the near future, to ensure the major changes needed are subject to effective systems engineering. We have already been exploring this with the industry through the IET’s Power Networks Joint Vision expert group. Our first report “Electricity Networks: A Shock to the System114” was published in December 2013, and we have been following this up with work funded by Innovate UK (the new name for the Technology Strategy Board) to explore what can be learnt from system architect and systems authority roles in other critical infrastructure sectors. This work will be published in early October115. We have also been working on behalf of the Council for Science and Technology on a study to identify the gaps in our modelling capabilities, to be completed in December 2014. 79. We are currently exploring the role of a system architect further with DECC and Ofgem 80. We would be keen to explore these very important issues with the Select Committee in oral evidence. 81. The opportunity exists now to put in place effective systems engineering arrangements for the electricity sector, which will allow a resilient low carbon infrastructure fit for the future to be delivered cost effectively, taking full account of new knowledge and technologies as they evolve. 82. Without this there is a risk that the electricity system will evolve in a piecemeal fashion, at higher costs and with significant risks to its resilience in the future.
114 Electricity Networks: A Shock to the System – IET position statement on the whole system challenges facing Britain’s electricity network, IET, December 2013. 115 Transforming the Energy System: How other sectors have met the challenge of whole-system integration, IET, October 2014.
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83. Beyond electricity, there will be a need for more coordinated local strategic spatial planning in the future to guide the development of electricity, heat and other infrastructure, in a world of increasing local power demand and the long-term transition from natural gas. About the IET 84. The Institution of Engineering and Technology (IET) is one of the world’s leading professional bodies for the engineering and technology community and, as a charity, is technically informed but independent. This submission has been prepared on behalf of the Board of Trustees by the IET’s Energy Policy Panel and takes into account input received from the wider membership. 19 September 2014
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The Institution of Engineering and Technology (IET) and the Royal Academy of Engineering – Oral evidence (QQ 1-16)
Evidence Session No. 1 Heard in Public Questions 1 – 16
TUESDAY 21 OCTOBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Lord Hennessy of Nympsfield Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Peston Viscount Ridley Lord Rees of Ludlow Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston ________________
Examination of Witnesses
Dr Simon Harrison, Chair of the Energy Policy Panel, Institution of Engineering and Technology, and Professor John Loughhead, Royal Academy of Engineering
Q1 The Chairman: Welcome to our two witnesses—our first witnesses for the formal evidence session on this inquiry. We are very grateful to have this contribution from the engineering community. I am going to ask Dr Harrison and Professor John Loughhead to introduce themselves in a moment and make any opening statement they would wish, but first I congratulate Professor John Loughhead on his appointment tomorrow, I think it is.
Professor Loughhead: It is indeed, Chairman, so thank you very much. They were keen that I should get this over with.
The Chairman: We have caught you before you are inhibited by the cares of office.
Professor Loughhead: That is right.
The Chairman: Excellent. I remind colleagues that they will have to declare interests when they first speak. Would you like to introduce yourselves and say anything by way of introduction?
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Dr Harrison: Thank you, Lord Chairman. I am Simon Harrison and I am representing the Institution of Engineering and Technology. I chair its Energy Policy Panel and we have reached back into our 150,000 members to form views about these kinds of things so I hope this is the concerted view of the engineering community in this area.
I declare an interest. I have a day job with Mott MacDonald, the engineering management and development consultancy. For an opening statement on resilience, a lot of your questions for today are about capacity margin and that is very important especially in the short term, but resilience is about a lot more than capacity margin. The response we provided to your consultation request explored a wide range of issues around electricity system resilience. The first thing to think about is that, in the engineering sense, resilience is a system property. It belongs to the whole end-to-end system from large power stations and even their fuels supplies, manufacturing supply chains, everything else through to what happens beyond the electricity meter in consumer premises. One has to think about resilience in the round and not in pieces, because if you think about it in pieces you will tend to end up missing important interactions.
The electricity system is a very complex system and it has worked very well, which means that we tend to take it for granted. Its resilience and engineering integrity are governed by a series of statutory appointed Code Panels and such like. It is about to transform and while generation capacity is a major concern for the short term, the much wider concern is what in Germany they call the Energiewende—the transformation of the system as we decarbonise it.
That is going to mean that the system becomes immensely more complicated. There are going to be immensely more cross-system and along-system interactions that need to be understood, managed and controlled. There will be many, many more automatic control systems engaged, ranging from systems for charging electric vehicles in people’s houses through to systems that deal with the technical management of the electricity system itself. There are issues of cybersecurity from end-to-end on the system as information and data become much more important to it. A lot of smartness is coming in, with demands from consumers for great smartness in the way they interact with the system and a massive expansion of renewable energy, and potentially distributed and community energy.
If you engineer all that well you will end up with a more resilient system. If you end up just hanging all these things on to what we have at the moment you will end up with a very much less resilient system that could well fall apart under particular circumstances, not all of which we could predict at the moment. The important message here is all about end-to-end systems engineering. Nobody at the moment is responsible for that. The IET is very keen to establish a proper system engineering function within the UK electricity sector and, as you will see, we majored on that in our response and you may have some questions for us about that later. In the short term of course, you are interested in capacity margins and we are very pleased to try to help with that if we can.
The Chairman: Thank you very much. Professor Loughhead, would you like to say anything?
Professor Loughhead: Yes. Thank you very much, Chairman. My name is John Loughhead. I am currently executive director of the UK Energy Research Centre. I am here today representing the Royal Academy of Engineering, where I am chair of the engineering policy committee. I should also make clear that I have been a member of the IET’s Energy Policy Panel and indeed its past chairman for several years.
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In terms of this particular inquiry, the Academy very much supports the detailed statements made by the IET and there is not very much that we would want to add to what Simon has just said as an opening statement. However, there are probably two issues that I would like to emphasise. The first is that we currently have a system that was designed and engineered some 50 or 60 years ago as a predominantly electro-mechanical engineering system with an assumption that most of the users of electricity were what we would call in engineering terms “passive loads”. That is they are dumb. They just consume. They are either switched on or switched off.
As Simon has highlighted, we are moving to a very different system in a context where much of the spare capacity that existed in the system 20 or 30 years ago has gradually been exploited and consumed. We now are operating on much smaller margins than we traditionally have and we are putting the new systems into both the generation and supply side but equally into the consumption side where we can no longer assume that some of the traditional tools such as voltage adjustment will necessarily result in control of load because of the intelligence and the reactive nature of many of the loads that are on there. Apart from that, I think Simon has very well summarised it.
Q2 The Chairman: Thank you very much. We will move into our questions, but before I ask the first question I should declare my interest as an honorary fellow of IET, a fellow of the Royal Society and chairman of the Foundation for Science and Technology.
In the evidence that you have given us, and indeed others, it is clear that in practice over the last 40 years or so the system has been highly reliable. The IET point out that the three-day week in the 1970s was the last time there was a serious issue. However, we seem to be in a situation now where the margins are narrower than they have been for a very long time. There are clearly some unexpected outages: we have just had a fire at Didcot, for example, and there are nuclear power stations and other power stations with planned closures. It is looking rather more precarious than perhaps it has for some time. Is this a concern over the next couple of years or so, certainly until the new balancing systems and the like come into existence? How have we got into a situation where we appear to have rather narrower margins than is comfortable?
Dr Harrison: You have highlighted the short-term concerns. Until the weekend we had about 2 gigawatts of plant on unplanned outage for well-publicised reasons and we now have another 750 megawatts or so. When you add that, you are talking about 5%-ish of peak demand. We do not really know when a lot of that will come back but it is a fair bet that we are unlikely to see most of it during much of the high-load periods during the winter. It has exacerbated a problem that was already there.
National Grid has been putting arrangements in place to procure what it calls “balancing services” in the short term from mothballed power stations, from industrial users who can deload and other such sources. Potentially that provides us with a few gigawatts of opportunity to help balance the system. There are opportunities around reducing system voltage but they are underexplored. We have not been in a situation where we have had to do that in a systematic way for many years. Frankly, we do not quite know what the extent of that opportunity is. The received wisdom is about 5% but, as John was saying, the nature of the load has changed. We have a lot more power electronic loads. National Grid will be the first to say that they are surprised sometimes with how load is now behaving. The
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implication of that is that, whereas you used to be able to reduce voltage and load would come down roughly in proportion, you now reduce voltage and you are not quite sure what is going to happen. There will, no doubt, be some discovery and there is certainly some opportunity around reduced voltage. As to whether the system will remain together and operating, yes, it will. There are, in extremis, means to manage load on the system. In other words, controlled disconnections of industry and such like can be done and will keep the thing on and lights available to ordinary consumers. We are much closer to the wind than I think we would probably like to be.
The Chairman: Professor Loughhead?
Professor Loughhead: In addition to that, the academy last year published a report on capacity margins and highlighted the fact that the result of the exploitation of unconventional gas particularly in the United States had caused a significant release of United States coal on to the north-west European market. That depressed prices. What it meant was that gas-fired power plant for a long period became uneconomic to operate and so you saw a dramatic increase in the amount of coal-fired power generation in this country.
Prices of gas have been supported by the closure of nuclear plants in Japan and the increasing amount of LNG on the world market, which has tended to exert an upward pressure on gas prices that has reinforced that. Then the incentivisation of renewables deployment in the UK has made, for many commercial investors, the outlook for gas-fired plants less certain. Therefore they have tended to shy away from investment in the UK environment because they are concerned about the risk of stranded assets. This is with a number of companies who also are countering the effect of the German Government’s decision to close nuclear plants early in Germany, which has hit the balance sheets of many of them and made them much less resilient. What we are seeing is a combination of world effects, the normal ups and downs of system operation, and the impact of some of the European policies and UK government policies, which have conspired together simply to take away what would have been the normal reaction of the operators of, “Let us invest”.
The Chairman: As an engineering community, you must be a little bit disappointed at the inability of those who plan these things to have anticipated these issues. Clearly the capacity market measures that have been taken are going to be expensive and that may be money that, quite frankly, could have been better spent in investment.
Professor Loughhead: We are engineers so we face disappointment every day, Chairman, but one of the issues that we are disappointed about is the fact that it has been obvious for some years that we have needed to take a more active role in looking at what the overall engineering conception of the system is going to be, but there has not been anybody so far who has been in the position to take that responsibility within the UK. What we have been doing is exploiting a system that we have. We can see the looming need to start to design it differently but at present it is not clear who is going to take up that responsibility.
Q3 Lord Wade of Chorlton: Thank you very much for that because I think you have created a very interesting point. I agree with you about this, if you like, Mr Energy, who can see all these issues, because we have never had anybody who can see the whole picture for a long time, if ever. The issue you raise is about the fact that we are no longer in the UK market; we are in a world market. Somehow or other this is not dawning on people to the extent that you would have thought it would. Even in my understanding of the agricultural industry, it is
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amazing now how it is world prices that decide the price of milk here and not what is happening here—an unheard-of situation, really. Are we not understanding, when we come to energy, that if we do not appreciate what other countries do will affect us, what is the point of us going to extreme cost to achieve an aim when somebody else takes exactly the opposite view and creates energy on a much more cheaply or does not take the same interest in controls or regulations or laws that we might? What they do will affect our market. How do you respond to that?
Professor Loughhead: The point that you make that we are operating now in a much more interconnected world is very good. It applies for the price of energy. It applies for the supply of the equipment. The last time we had a major expansion in this country, predominantly it was indigenously manufactured and designed. If we now expand the electricity system probably 80% or more of the equipment will have to be sourced from outside the UK because we no longer have such industries in the UK. The other factor that is worth reporting is that many of these organisations are making commercial investment decisions and there are a number of markets in which they can invest. It is not a matter of saying, “What is the best option in the UK context?” It is the question of saying, “Shall I put my money in the UK or shall I invest in Brazil and Venezuela or should I be putting it somewhere else?”
Lord Broers: I have a detailed question for Dr Harrison.
The Chairman: Declare your interests.
Q4 Lord Broers: Yes, and declare my interest as a fellow of the Royal Academy of Engineering, the Royal Society and the IET. You mentioned using voltage drops. Somewhere in your report, I think, I was surprised that you said that a lot of local generation will disconnect if that happens. How serious is that problem?
Dr Harrison: Local generation will not disconnect ordinarily if we manage the system voltage down a bit. Where it would disconnect is if there was a fault on the system or an excursion of frequency, such as might occur if, say, a large power station tripped out. That causes a short-term transient in the system frequency. Among the controls in small generation are things called rate of change of frequency relays, which are set to disconnect during fast frequency excursions. There has already been one round of resetting all those relays to different settings to make them less sensitive to make that happen less often. We are now in a process of having to go round and do all that again, make them less sensitive still, because clearly you want to be in a situation where you can use your local generation to help you recover from a frequency excursion. It is a very technical but interesting example of the need for systems engineering. The ROCOF relays were there for a particular purpose but we now have to look at them again.
Lord Broers: Will they be corrected by the crisis, the nominal low point that is coming up?
Dr Harrison: At the moment there is a programme of resetting of those relays ongoing. I am not personally aware—I do not know if you know, John—of what the time scale for that is.
Professor Loughhead: No, but it will be long. It will be a long time scale.
Dr Harrison: Yes.
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Q5 Lord Dixon-Smith: I have no interests to declare. Are we not in some danger at the present time of allowing what I would call short-term market effects to drive what is actually happening? The depression of America’s coal price, which was keeping our coal-fired power stations going, is not going to end in my view, because the increasing prospects of shale gas being developed globally is going to keep the coal market permanently depressed. Of course then we have an immediate conflict with the long-term global climate ambitions if that is the way we allow our policy to be run. How do we prevent these short-term aberrations, which is really what it is, from taking control of events which we need to keep under control?
Professor Loughhead: Let me make a response to that. You cannot insulate yourself from short-term aberrations because, sadly, we still cannot see the future with any certainty. That is one of the reasons why we have advocated the need to look very carefully at what the underpinning engineering concepts of the future system are going to be so that we can be more tolerant of those changes but have a more responsive system within which we can adapt to that. If I may just quickly return to the previous point, one of the reasons why there is disconnection once the system goes outside certain limits is simply that the system architecture assumes that everything below transmission level is a distribution of electricity. One of the big dangers you have is if you do not stop everything working when the system has a fault is that you could be generating down at the end of a line where all the systems and processes tell you it ought to be dead. It is a hazard for the people who have to work on it and the systems cannot currently cope with that. We are stretching, with the embedded generation, the capability of the system beyond where it was. To return to your main point, one of the things we have to do in the future is be clearer about how we will cope with the inevitable uncertainties. We cannot control what is going to happen.
Dr Harrison: Perhaps I may add to that. If one looks back through energy policy and on roughly a 10-year cycle, the decisions, as seen looking backwards 10 years, are always wrong. There are external circumstances that change that we have to be able to respond to. It is unwise to be too prescriptive and fixed about how you look at the future but we do need perhaps something that is more considered than we have at the moment.
Q6 Lord Peston: I am going to ask you about balancing, which I confess I do not understand, so I want a layman’s guide in a minute, but could I just ask you a question of context? Today it is bad weather and a lot of flights have been cancelled at Heathrow and a lot of people have been inconvenienced but there is no great song and dance about it. It just happens because an external shock has hit the system. Can you tell me why power generation is any different? Supposing there was an outage tonight so a lot of people could not watch Chelsea play European football. Would it matter? Are we not making too much of a song and dance about this whole subject? I speak as someone who was the first person ever to teach the engineers at Imperial some economics and that was 50 years ago.
Professor Loughhead: That is great. I might have listened to you. The issue about whether it matters is critical. The academy is currently preparing an extension to its report of last year looking at impacts of potential shortfall in supply. One thing that comes from that is that first of all it is very difficult to say how important it is depending on who you are. For some people it is critically important. This is embodied in the UK in something called “Value of lost load or willingness to pay”. When you look at the evidence on that, it ranges from figures of about 20p a kilowatt hour up to £50 a kilowatt hour depending on who you are. The answer is that we do not know.
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One of the reasons for that is that we have very little experience on which to base the concept of reaction. From what has been done in various parts of the world, there are two instances. People are very tolerant of what are seen as unavoidable external impacts. If a fire hits a power station or something dramatic happens, then they behave as “citizens”—that is the phrase. If, however, that persists for much time or alternatively it is seen that there is no response to it, people then move into being “consumers” and their response is, “Why has somebody not done something about it?”
Finally, to add to that, the last experience we had of sustained shortages was 40 years ago. Since that time we have become very much more dependent upon reliable electricity supplies. If you look simply at the City of London, most of the buildings would be utterly unusable. A two-day outage would start to become catastrophic and that is without talking about computers and all the rest of it. We are treading into very much unknown territory. We do not quite know what might happen.
Lord Peston: I literally do not understand what balancing does and what it is meant to do, so can you tell me what I need to know?
Dr Harrison: Okay, in concept it is quite simple. You cannot store electricity; you can only store it by converting into something else and then retrieving it. Because you cannot store it, you have to make it exactly as fast as you use it. We do not have Tesco warehouses for electricity. The result of that is you have to manage your supply to meet your demand at every second of the day, and National Grid is responsible for doing that in GB.
Within the market environment, we have generators and suppliers contract with each other to provide electricity to meet demand, but you can end up with an imbalance that you need to address in some way or another. You can address it either by reducing demand or by increasing supply, or you could address it if you have arranged to convert some electricity into another form to store it by recovering from your store. In the UK we have a few stores. They are large pumped storage hydroelectric stations that have been there for many decades, so you can store within those and recover to a degree. That is done on a commercial basis. Balancing is simply no more than the art of instantaneously matching supply and demand.
Lord Peston: That means, does it not, that the capacity has to be larger than the mean use. In stochastic terms it is the variance that matters and therefore balancing really has to give you the capacity that meets something at one great end of the spectrum.
Dr Harrison: Yes, you need more capacity by some considerable margin installed on the system than the maximum demand that you are likely to experience to allow for planned maintenance, for breakdowns and, in the more complex world we are now in, things like the wind not blowing when you might like it to. There is an elaborate way of calculating how much capacity you think you should need to keep the amount, the probability of lost loads, to an acceptable level. It can never be zero.
Lord Peston: What I am also supposed to ask you is, therefore: what can go wrong or what is likely to go wrong on present forecasts?
Dr Harrison: I guess where we are at the moment is the market has not brought forth enough new capacity that is reliably available at times of peak demand to offset the closure of old capacity, and the reason that old capacity has closed is not because of market issues but because of regulatory issues, because of emissions reductions and so on.
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Professor Loughhead: Could I just quickly add to that? There is also the fact that the system is changing. As well as the elements that Simon has just mentioned, there are short-term lumps and bumps on the system due to sudden attachments or disconnections of load that you need to ride through and, if you do not—what we were talking about earlier—the rate of change of frequency causes protection to come in and the system to switch off. One of the issues that we have is that we were helped by the very large inertia of conventional coal-fired power plants, which would enable the ride-through of those lumps and bumps by using the enormous kinetic energy stored in the system. Newer systems do not have that, so you need to reproduce it in some way and we do not have that to reproduce. The second element is that we can control some of this by using tolerances on the voltage that is supplied or on the frequency of electricity that is supplied. There are legal limits that they have to stay within but we can try to use those. But as we mentioned, the impact of those changes is being diminished by the intelligence of the devices sucking the energy in. The final point it is worth thinking about. We focus on generating capacity. We have to move it around the country. There are probably half a dozen pinch points on the national transmission system where a fault could seriously degrade the capability of the supply mechanism. All these things can conspire together. As you reduce the margins, the chances that you might go outside the acceptable envelope increase, and the longer you try to operate at those margins, the cumulative risk of something going wrong tends to increase.
Q7 Lord Rees of Ludlow: I have a comment and a question. The comment was in the evidence we had from Professors Grubb and Newbery, who thought there might be a risk of paying too high an insurance premium for this. Maybe you would like to comment later. But I would like to ask the question: when these rather precise figures are quoted, like the one in 31 years and one in 73 years, what are the main risks? Is it systems breakdown or is it extreme weather? Also, I worry that the circumstances are changing decade by decade, so we do not know what the risks will be 20 years from now. I wonder if you would comment on those. I should declare an interest as a member of the Royal Society.
Professor Loughhead: Can I just clarify the figures? You said one in 73. You are quoting those from where?
Lord Rees of Ludlow: Yes, Ofgem figures.
Professor Loughhead: Ofgem figures?
Lord Rees of Ludlow: Yes.
Professor Loughhead: All right. Well, they must be right then. Do you want to say anything on that?
Dr Harrison: What are the main risks?
Lord Rees of Ludlow: Yes.
Dr Harrison: I think, historically, the main reasons why people have gone off supply have been nothing much at all to do with generating capacity. They have been mostly to do with distribution system performance and a little bit to do with transmission system performance, and a tiny bit to do with generating capacity. So we need to just keep that in our minds, I think, when looking at this whole resilience issue. My opening statement and our submission were directed around that. Going further into the future, distribution system resilience and its interaction with supply we think will become the main game in town
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around system resilience. Therefore the importance of looking at the whole thing end to end just gets bigger and bigger. In the shorter term, we have this concern about supply, available capacity and the ability to manage demands to keep the system balanced.
Lord Rees of Ludlow: That is in case of extreme bad weather.
Dr Harrison: That is in case of mixes that are changing. It could be very cold weather that produces high demand at the same time as producing low wind conditions, for example. That could be a pinch condition. Other pinch conditions could be around unexpected outages of, say, nuclear plants. If you combined all that with, say, a well planned terrorist attack, you could be in quite a mess. So it is those kinds of issues, I guess, in the shorter term.
The Chairman: Your reference to the distribution system reminds me that perhaps I have another interest to declare, and that is that I spent Christmas without any electricity—a failure of the distribution system—and it gave me a rather jaundiced view about the communications of the company, which was pretty inefficient.
Q8 Lord Dixon-Smith: We are now fairly well informed on the problems of the supply side, but increasingly we are going to have to go into the question of managing the demand side. Could you just expand on how you see that going into the future?
Dr Harrison: Setting aside the problems of this winter, I think the question is aimed a little bit into the longer term, is it not?
Lord Dixon-Smith: Yes.
Dr Harrison: There are all sorts of opportunities around this, because there are large amounts of industrial and commercial demand where you have intelligent actors who are able to make rational, commercial decisions about when they take electricity or when they do not take electricity. The classic example is supermarket refrigeration. There is no reason why, at a time of peak, you cannot contract to turn some of that off and receive a commercial benefit for so doing. This is happening now and will happen to a greater degree in the future. The transformation, I guess, is when you start to extend that into people’s houses and you start to envisage contracting for blocks of demand within residential premises. There are some experiments going on with that at the moment. The smart metering programme will help make that a little bit easier.
But there is a whole end-to-end piece around this, because if you do start doing interesting things with consumer demand, you need to start worrying about the impact on distribution networks, for example, voltage control and suchlike. It is all linked in also with things like solar PV panels on people’s roofs and what that does. If we move to a world of electric vehicles or heat pumps, they have massive implications for demand levels. So the average demand of a house at the moment is about 1.5 kilowatts, while an electric vehicle charging load is about 7.5 kilowatts. So you have really major implications if you move to that, including for distribution systems. You start to get to a place where you need to understand both the impact on supply-demand balance of managing demand and the impact on the network. That is a major concern that we have, because there is nobody looking at that. You are either a generator selling electricity and you are very interested in managing when your customers take it, perhaps, or you are a network company trying to manage your network, but there is no real interaction there. That is an interesting issue. The other one that we
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foresee that potentially could come up and just overtake a lot of this is big consumer brands like Apple and Google, who are investing heavily in consumer energy products at the moment, coming in and capturing people’s imagination and taking control of their domestic energy economy in ways that we can hardly imagine that will have deep, profound and rapid implications for the electricity system. The chances are that that would happen in a completely disconnected way from what is happening in terms of how network companies act and invest.
Baroness Manningham-Buller: Can you explain the Google-Apple thing? I do not understand.
Dr Harrison: For example, Google has spent a lot of money acquiring a business called Nest, which makes intelligent thermostats. Now that might not sound very Google. A thermostat does not seem to be a particularly sophisticated device. But they are seeing that as part of, I guess, a service offering where they can provide an intelligent, very controllable, very user-friendly home energy control service. In a way, I suppose, the smart metering programme is an early step along that particular direction. But you imagine the transformative power of Google, in terms of disrupting a business model, and providing an offering to you as a customer that you find highly attractive, that reduces your bills and takes a significant element of control of the energy in your home. Now, the thing that is interesting about that is not just that it can happen but the way consumers behave when that kind of disruptive change happens.
We have seen it with mobile phones or with deployment of solar PV panels. It can happen really fast. The electricity industry tends to work in timescales of many years to implement changes. The consumer electronics industry works in two- or three-year cycles. So, if we suddenly got to that place where, in 10 years’ time we were sitting around this table and you were all driving Google cars and you were all controlling your home with an Apple home control app, then the implications of that for electricity system investment, which tends to be rather slower moving, could be profound indeed.
Baroness Manningham-Buller: I should declare an interest. I am chair of Imperial College.
Q9 Viscount Ridley: I declare an interest in coal mining, one wind turbine and shares in Rio Tinto. Just to pursue a bit more what happens on the high peak demand periods, there is a short-term operating reserve, which the system has been building up to switch on for minutes, hours—I am not quite sure—and a lot of that is dependent on diesel generators, am I right? How much diesel, as it were, are we going to burn to keep the lights on in the next winter?
Professor Loughhead: The answer is not a lot, in the sense that these are to shave off short-term peaks, to stop the point where the system would need to start switching off for protective reasons. So the total amount of operation is probably at most a few 10s of hours per year.
Viscount Ridley: Okay. But is it sitting there waiting if we need it? Is it big enough?
Professor Loughhead: It is sitting there doing it. I honestly do not know. Everybody hopes it is, but we will find out.
Q10 Lord O’Neill of Clackmannan: Can I first declare an interest? I advise the Electrical Contractors’ Association and I chair stakeholder advisory panels for both Scottish Power and
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National Grid. Could we return to the capacity market? You either forgot or sidestepped the question that Professor Rees raised on the Newbery and Grubb criticism, and I wondered if you could perhaps say whether or not you accept their view, or what you think of their view, that 53.5 gigawatts is in fact excessive, that we have targets of investment that are higher than we require? What is your view on that criticism?
Dr Harrison: It is certainly a risk. The way in which that 53.5 gigawatts has been set has been a piece of analysis done by DECC and by National Grid that essentially makes a whole series of technical assumptions about all manner of aspects of plant performance—availability data for thermal and nuclear power stations, ramp rates and the whole gamut of technical parameters. All those are subjective. Imports off interconnectors is another quite contentious one. You have to form a view as to where you think each of those should sit. Rather than necessarily challenge the 53.5 from the top, you have to start with all the inputs and look at them. The IET feels that some of those choices were made quite conservatively. However, we can understand caution because the costs to society of getting that 53.5 gigawatts too low by, say, 3.5 gigawatts are much higher than the costs of getting it too high by 3.5 gigawatts. So there is a drive towards caution in approaching this, but certainly the IET is on record as having made comment that we feel that some of those numbers were set perhaps a little too cautiously, but we can understand the thinking behind doing that.
Lord O’Neill of Clackmannan: It is a fact that the old system, the publicly owned one, lent itself to gold-plating, and I would imagine the received wisdom in the industry still has a residual element of that within it, so that would perhaps give some weight to this, if not criticism, certainly questioning, if I can put it that way.
Professor Loughhead: I think you are probably right, because we have a whole generation of people in the industry who have been trained to assure supply. It is the old phrase of keeping the lights on and, of course, we can engineer a system to be as secure or as unsecure as you want. It is always a question of how much do you want to pay for it. I think that is one of the reasons, and I am sorry if I am anticipating your next line, why the engineering community has been advocating a system analysis of what it is that we are going to do, with a view of saying how can we most efficiently engineer the system, with all these different characteristics that policies demand we have.
Lord O’Neill of Clackmannan: Can I just ask you then—looking for a one word answer—whether you think that the present process of establishing these figures has been insufficiently rigorous?
Professor Loughhead: I am sorry, but it is more than one word. I think that the process has been imposing upon the system that we have inherited the moves that we believe we can make to get the performance that we want. Perhaps that is not the way we should be doing it, going forward. We should be taking a more fundamental look at how we are going to design and structure it.
Q11 Lord O’Neill of Clackmannan: Perhaps we could just move on to one other issue. We have already spoken about the availability of gas in North America and its depressing effect on coal prices, therefore making it more attractive for our coal stations to be fired and operating. How long do you think this can carry on? Will the capacity market assist this process of making coal fashionable once again? There is, at the back of all this, both the EU
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and our own carbon emissions reduction targets. What do you think the consequences are for both the life of coal and, as a consequence of that, the carbon emissions target problem?
Dr Harrison: That is an interesting point. Most of what is going to determine how many hours the UK’s coal fleet operates is nothing to do with carbon. It is limits that were set by the EU to do with sulphur emissions and nitrous oxide emissions. So there is the Large Combustion Plant Directive 2, which is around sulphur emissions, and another one called the Industrial Emissions Directive, which governs nitrous oxide emissions. Now, the impact of those is that most, if not all—probably not quite all—the coal fleet in the UK has a clock ticking in terms of the number of allowed operating hours that it has remaining. Whether it uses those operating hours quickly, by running hard to take advantage of the coal price, or whether it deems it more commercially advantageous to bid into the capacity market and use those hours over a long period and receive capacity payments is a commercial decision for the operators of those plants. The impact of that on carbon emissions will be neutral, give or take, because the number of operating hours will be the same, whether they are spread over a couple of years or another 10. If we are to see a longer-term future for coal-fired generation in the UK, we are then looking at carbon capture and storage possibilities, either as retrofits to existing plants or as new builds. Of course, the CCS competition that the Government is organising is live, and there are two parties that are looking hard at their feed studies at the moment. We may see, with supports, positive developments coming from that that would allow continuation of coal-fired generation with much reduced carbon emissions.
Lord O’Neill of Clackmannan: As engineers, what do you think the chances are of securing, within our lifetimes, CCS?
Professor Loughhead: Can I answer that? As engineers, no problem. The question is: will the market conditions make it possible? I was in Canada just over a week ago, talking to the people running the CCS plant there. Their big problem is, they say, that it just does not stack up economically, because it costs twice as much to build, it costs 30% more to run and, at the moment, there is no mechanism to get the money back. Doing it is not the problem.
The Chairman: Thank you. That brings us on to decarbonisation, and Lord Ridley has a question.
Q12 Viscount Ridley: Yes. You mentioned a little earlier that the coldest periods are often the ones with the least wind, and in December 2010 we had a particularly still and a particularly cold period. We nearly ran out of gas at the point, as I understand. If that had happened now when, first, we are more dependent on wind and, second, we have a series of outages and our capacity is lower still, we might be in trouble. I am not asking you to judge how likely that is. The point is that there is no question, surely, but that renewables reduce the resilience of the system.
Dr Harrison: That depends. If you are looking at resilience against fuel supply shocks, against gas price and suchlike, renewables increase the resilience of the system.
Viscount Ridley: But what about gas prices falling? They reduce your ability to cash in on that.
Dr Harrison: They reduce your ability to cash in on that. Resilience is a very complicated and multi-dimensional issue. You can view it through all sorts of lenses and, of course, people who favour particular technologies choose their lens. We try to be as balanced about this as we can, in the engineering profession. Renewables certainly have a contribution to make in
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reducing the risk of fuel price volatility and the risk of fuel supply. However, they have significant consequences for other aspects of resilience to do with capacity, and also to do with network performance. So we are moving to a world, as we decarbonise, where resilience could be quite severely compromised if everything is not engineered properly. As engineers, we can fix that, but we need the ability to look across the whole system to allow us to do that.
Viscount Ridley: You can fix it, but at a cost, presumably. In other words, you talked about it ensuring against volatility of fuel prices and so on, but only by raising the cost of electricity.
Dr Harrison: We are getting into a space that goes somewhat beyond engineering.
Viscount Ridley: I am sorry. That is fine.
Dr Harrison: If we engineer it properly, we can fix it at a much, much lower cost than if we simply react and fix the problems one by one as they emerge. If we were to choose not to deploy renewables and to do something else—for example, to fill the UK with nuclear power stations—it is potentially a viable solution, but you end up with a whole lot of other resilience issues. They revolve around skills, around the supply chain, around dealing with the spent fuel and decommissioning issues in the long term, and so on, on a much greater scale than we have now. So these debates are very complex and multi-dimensional, and beyond engineering. As engineers, we can build you whatever system you would like, but it is a matter of what the public want.
Q13 Viscount Ridley: Can I ask you about storage, because there is a lot of hope that efficient storage, in batteries or some other form, can solve this problem of renewables being dependent on what happens to the weather? On the other hand, I have seen some studies—there was a study that came out of Germany recently—that even if you take pumped hydro storage, which is the most efficient form of storage, and add that on to wind—you firm wind with that—the effect is basically to lower the energy return on energy invested in wind to the point where it is uneconomic. Have you seen that, and does that worry you? In other words, however good batteries get, they cannot make wind economic if you are storing it.
Professor Loughhead: Could I make a response to that? I think, if I may say so, you need to think of storage much more broadly than that. It is not just about storing electrons. There are all sorts of ways in which you can store energy. We inferred it before, talking about using the thermal inertia of refrigerated or deep freeze stores as an energy swing methodology. You can do the same thing with heating. There are many different ways in which you can store energy. Every system that is going to be engineered is going to need energy storage in it in some form or another, whether it is a pile of coal at the entrance of a power station, whether it is a gas store somewhere in the North Sea, whether it is a thermal store or whether it is a mass of batteries. The question is, rather than picking the silver bullet of electricity storage, to say what your system is going to look like overall and how you will you create the necessary storage within the energy system in totality, because the electricity system is not wholly separated from the heat system and the transport system.
Dr Harrison: If I can give one example of that, there are opportunities that have been exploited in some countries for inter-seasonal heat storage in aquifers under buildings in cities. So, the excess heat in a building in the summer is stored underneath the building and recovered during the winter.
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Viscount Ridley: I suppose I am specifically saying: how do you store wind energy?
Dr Harrison: There are all sorts of possible mechanisms, which mostly have not been exploited. One obvious use is, for example, if there is far too much wind energy at a particular time, you could store it very simply in everybody’s domestic water tank via an immersion heater.
Q14 Lord Broers: This one is rather specifically for you, Dr Harrison. The IET has called for a new systems architect. Can you explain why this systems architect is needed, and what form it should take? I might add my own slant to that, in that DECC, for a long time, has had a calculator that to me as an engineer was quite remarkable because it completely ignored cost. Do you think that this architect will be able to look at the whole system, including cost? What is your concept for this?
Dr Harrison: We are thinking about the functionality of this because we think the need to look across a whole system that is becoming very complex and changing very fast is missing at the moment, and needs to be filled. As to the precise form of where you put it in government, and who it reports to, and all the rest, lots of people want to draw us into that conversation but we are trying to avoid it because we think it is not an engineering problem. The engineering is about why we need it and what it should do. We think that, because there are massive changes coming in the way our electricity system, and indeed, our whole energy system is going to be in coming decades, we need to do some proper systems engineering to understand that. In fact, it is interesting. We have done some work funded by Innovate UK on how this is looked at in other sectors. If you go and look at other complex engineering sectors and try to have a conversation about why you need systems engineering, they look at you askance and say this is a bizarre conversation. It is an absolute basic thing that you need to look at the engineering of a whole system.
What we would like a system architect to develop an end-to-end understanding of is, for example, all the interactions of control systems that are going to happen on this very complex, data-heavy system that the electricity system is becoming. Just by way of examples, and I can hand this out if it is of any interest, we have at the moment about 10,000 automatic controls on our distribution systems. They are things like transformer tap changers. The calculations we have done indicate that, as the system smartens, that 10,000 changes to 900,000. So you then have 900,000 interacting systems to start to worry about, which nobody is taking care of right now. We, at the moment, control the frequency with 10 to 15 generators in frequency control mode. We potentially could see that increasing to somewhere north of half a million, when you start to include all the autonomous generators locally connected at small scale.
If we move to very intensive home energy management, which I think is highly likely, we move from almost nothing at the moment to perhaps 15 million [control systems], if half the smart meters that go in link to energy management devices. So you are ending up with a data-heavy system with many different controls going on within it, which needs to be thought about end to end, because if you do not, you will end up with control systems fighting each other. For example, if you decided, because the wind was low, that you wanted to turn off all the fridges in Kent one summer’s evening, that might be a rational thing to do. However, if at that point the sun suddenly came out and all the solar PV in Kent started generating, you end up with serious voltage rise problems around the network in Kent that need a proper control response. Unless all that is thought through, you have a risk of
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voltages going outside limits, equipment damage, and so on. You can come up with many examples that explore and clarify why you need this end-to-end view. What we do not want is another CEGB. This is not a bunch of engineers asking for another CEGB. The CEGB was not a particularly cost-efficient way of delivering. It is about a systems integration activity at the engineering level that runs in parallel to economic regulation, the role of markets and so on. It is not working against any of that, but it is providing the systems rigour that is missing at the moment.
Q15 Lord Broers: What does this proposal mean for existing actors with responsibility for electricity system resilience, particularly the Government, the National Grid and Ofgem?
Dr Harrison: National Grid, I think one can argue, takes the lead within the industry at the moment and its job is to balance the system and to provide the transmission infrastructure for bulk transfer of power. What it does not do or understand—and would be the first to claim, I think—is what happens on the distribution system, what happens to the customer side of the meter, which is becoming increasingly important, or how consumers behave, which is a significant issue going forward as customers become more engaged with their supplies, as we expect to happen. So, National Grid has a view of a system, but not a view of the complete system. This is going to be quite tricky, because it is a dominant and very knowledgeable player, but it does not have a complete view. A system architect needs to be positioned to have that complete view but not to interfere unnecessarily in the proper business of a company like National Grid, which does have a large competence, and nobody wants there to be unnecessary technical arguments between what National Grid should and should not do within its sphere of activity. But National Grid’s role within a total system is very much part of what a system architect should get involved in.
If you look at Governments, DECC, of course, is the owner of policy in government and the system architect is not envisaged to be any kind of policymaking body. The system architect is an engineering systems integrator. The system architect we would expect to be a trusted adviser to DECC by providing the engineering knowledge that allows DECC to think about and understand the engineering implications end to end of policy decisions and, hopefully, then to make better policy decisions. It is not making policy but what it—
Lord Broers: Is it a person or a committee or what is it?
Dr Harrison: That is one of the questions we think is unanswered. It could, at one level, be a committee. It could, at another level, be a staffed body carrying significant expertise. That is something that needs further development by the industry and with Government to understand what this thing is and what its rules of engagement need to be. At the moment what we are trying to do is to get the whole subject into the productive debate that is about confirming that it is needed and then thinking about what its form should be and what its remit should be.
Lord Broers: You are defining a need, rather than an actual committee or person. This is the very beginning of solving this issue.
Dr Harrison: Yes, it is. We have produced a number of reports—which we would be very pleased to share with the Committee, should you so wish—which set out the thinking as it has emerged. We have explored what is done in other sectors. We think now we have a case that is reasonably well set out as to why it is needed. From our point of view our next steps are to look at the engineering of that and what the scope needs to be. It is quite a different
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question from what most people seem to want to ask us, which is who it is or where it should sit. We are trying to not answer that question because we think that is leading the witness. We would much rather say, in engineering terms, what it should do and then leave it, essentially, to Government to work out how it should be—
Lord Broers: This is an example of engineers being politically naive, whereas politicians are financially naive.
Dr Harrison: We may be politically naive. In this company, I have to say, we are, almost by definition. But we are trying to engage at a level that builds a consensus of understanding and acceptance of need, rather than polarises a debate where you say it should be part of Ofgem and you say it should be part of DECC and you say National Grid should do it and you say it should be a new body and you say it is not needed at all. We are trying to get away from that at this stage to focus on need and develop scope and build an understanding that this very, very complex system that we are moving towards needs proper systems engineering.
The Chairman: We are running out of time on this session but I want to take Lord Willis and then Lord Wade.
Q16 Lord Willis of Knaresborough: Could I just follow up? I was disappointed that you did not give us your solution to what in fact this architect should be because, as a Committee, it would help us if in fact we had a steer in order for us to debate that and then have a recommendation. Perhaps you could think about that and say, in an ideal world, if you were sat on this Committee, what your solution would be, because that would be helpful. But the question I wanted to ask you is this. Most systems that we see, particularly around Europe rather than the States, were all monopoly systems that were basically set up and engineered by organs of government in the past, so everybody must in fact be dealing with the same problem. Is there anywhere that you could point to that in fact has a system analysis and has converted that into a policy proposal in order to secure both their supply and their resilience?
Dr Harrison: Answer: not yet, but lots of people thinking about it. For countries experiencing similar issues to the UK—for example, Australia and Germany—it is very much in debate. The UK is relatively unusual, as we have liberalised rather more than everywhere else, which has had large numbers of benefits but has also produced greater fragmentation in the industry than elsewhere. That works against end-to-end systems engineering. We are very open in terms of consumer markets, which is why we are likely to be attractive as a test bed for new ways of managing energy in the home and bringing energy to people. We are ahead of the curve. The country that is experiencing the issues around renewables more than anyone else is Ireland and so there are, potentially, some interesting lessons to learn from Ireland. But Ireland is less well advanced in terms of some of the issues around consumer interactions and so on.
The Chairman: I must bring this to a close. Lord Wade, finally, a short question.
Lord Wade of Chorlton: Very quickly, Chairman. But also I will just say that my interests are that I am a director of a fund management company where we invest into a whole range of different companies. The question I was going to put to you is that I have sat on a number of Committees—two Committees other than this one—looking at energy issues and we always ended up asking the question: if the lights go out, who gets fired? When you think about it,
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you always get a very confusing answer because there are so many people involved that there is nobody whom you shoot if the light goes out. Are you adding to that pile of people who can always say, “It was not my fault that the lights went out, it is his fault”? I come to the conclusion, when I hear you talk, that there is only one way of running our energy policy and that is with a bloody big computer that is given the responsibility to take in all this vast amount of information and tell us the day before, “The lights are going to go out tomorrow”. Am I right?
The Chairman: A quick reply.
Professor Loughhead: A quick reply to that is that operationally there is no one responsible to do that. The point that Simon was expounding was that we need to accept that as we move towards the utterly different components that stretch our current system beyond its capability, we need to approach its design in the right way. I do not think we are adding to the operational confusion; that is another issue.
The Chairman: Dr Harrison, you said that there was a document you would like to circulate to the Committee. If you give that to the clerk afterwards, he can send it around by e-mail. I get the feeling on this systems architect that this is very much at the moment a matter for discussion, so if you develop your thoughts further, of course, we would be very interested to hear. I have no doubt we will refer back in future evidence sessions to your interesting ideas in that respect. For that and for the other evidence you have given us today we are most grateful. It has been very helpful. Thank you very much.
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The Institution of Engineering and Technology (IET) – Supplementary written evidence (REI0052) Resilience of Electricity Infrastructure Introduction 1. Following the IET’s submission of oral evidence to the Committee on 21 October 2014 the IET was requested to provide more developed thinking on the electricity system architect (SA) role. This document contains that thinking, which has been developed through continuing engagement with engineering professionals within the power network industry and associated academics and other stakeholders.
2. It is fair to say that whilst there is wide industry consensus on the need to introduce effective whole systems thinking, debate continues on the most appropriate institutional response and how this should be shared between government and industry self-regulation. For example, whilst network companies fully appreciate the need for strengthened system integration, they are concerned over the possibility of close government engagement in aspects of their business that require specialist technical knowledge and experience, and which might be more effectively managed, at least as a first stage, through the development of existing industry governance mechanisms (known as the Code Panels).
3. Our response has therefore been structured to major on the scope required, irrespective of the mode of delivery, and then considers how the mode of delivery should be determined, without making specific recommendations at this stage. The scale of the challenge 4. In his oral evidence for the IET Dr Harrison referred to the dramatic increase in complexity between now and 2030 as Britain’s electricity system is adapted to a low carbon future. The graphic developed by the IET, to which he referred, is reproduced in Figure 1.
5. This highlights the disruptive changes ahead, which are material in scale. The power networks will have an increasing penetration of automation and intelligent systems, and will deploy entirely new devices featuring power electronics and other advanced, fast-acting control systems. Under these significant changes, the GB System Operator, along with the Transmission Owners and Distribution Network Operators will be faced with a significantly more complex system to operate as a result of the development of Low Carbon Technologies, new market arrangements and increased customer participation.
6. Smart Cities and Smart Communities developments are active in many countries, both in Britain and internationally. These are potentially autonomous zones embedded within the national electricity system (at city or community scale), and the behaviours of such zones will be in response to local resource availability, local customer behaviour and pricing. This introduces new uncertainties and could have a large impact on local and national power system requirements and opportunities.
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Figure 1
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7. The GB System Operator and the network companies have already started to experience some of the problems associated with these changes, for example:
reversal of power flows created by distributed generation;
greater variations in system frequency resulting from new types of generator interfaces (power electronics connected devices), and
rising transmission voltages as a consequence of changing demand characteristics in the distribution networks.
Outcomes desired from a System Architect role 8. However delivered, thinking to date is that the SA role needs to achieve the following high level outcomes:
High level ‘systems engineering’ that assures end-to-end coherent technical integration, capable of delivering a secure, resilient, cost-effective, low carbon electricity system for Britain. This must encompass all parties in the engineering chain and, where relevant, commercial frameworks that interact with it. This will include active consumers, generators and storage operators, all of the electricity networks, and new third party entrants;
Engineering modelling that allows safe operating limits to be understood, and avoids unwelcome surprises affecting supply resilience. We would expect this to be by directing, enabling and supporting modelling rather than undertaking it;
Active support for innovation by network owners, system users, manufacturers, vendors and service providers, through establishing open systems and interoperability approaches, balancing the type and timing of standardisation to not hinder fresh thinking, while helping to ensure adequate security in an open systems environment;
A resilient overall power system architecture that facilitates current and future government policy, with flexibility to accommodate a changing pathway;
Equipped to be adaptable to change, including the possibility of evolving into a whole energy system architect, should this become a desirable future development, and able to interact effectively with emerging energy third parties beyond the established and regulated sector, such as home energy management providers and smart communities.
9. For clarity this is not a proposal for a GB Chief Engineer or a move towards formal central planning; it is intended to be a catalyst for markets and private companies as we enter a time of fundamental electricity system changes. The broad remit of the system architect role 10. However delivered, the SA role needs to focus on those issues that individual electricity system participants cannot handle individually or bilaterally. We envisage the SA
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to coordinate and integrate with other bodies, rather than duplicate or subsume them, unless mutually agreed. Further review and debate is needed to find the appropriate balance in this area, but current thinking is broadly as follows.
11. In regard to relationships it would -
Work with parties across the industry to ensure an efficient, coordinated and integrated whole-system national electricity system development strategy, with regard to whole system independence, including fully active consumers, and markets;
Work with vendors such as appliance manufacturers (and related European standardisation bodies) and service providers (such as aggregators), including supply chains and interactions with commercial frameworks, to the extent to which these influence or could influence whole system engineering outcomes;
Include the consumer side of the meter, home energy automation and time of day pricing impacts, recognising that acceleration of the pace of development in this area is likely anyhow and will be catalysed even further by the smart meter rollout and new market entrants;
Consider key interactions with other energy vectors (for example at consumer level), including gas, heat, cooling, hydrogen, and supply security aspects of input fuels to the extent this has system impact;
Advise policy makers on the feasibility of energy scenarios, possible alternative scenarios, and/or the modelling necessary to test feasibility using their existing models (as developed over time);
Provide a source of advice to Ofgem on the merits of discretionary (or “least regrets”) investment, demonstrated by the SA to be in the public and consumer interest.
12. In regard to functions it would -
Facilitate, in collaboration with Ofgem, a change from incremental to strategic approaches to foreseeable future developments. This could include assuring a more coordinated electricity system innovation strategy aligned to current and anticipated system challenges, in conjunction with current competitive approaches;
Provide broad functional frameworks to enable decentralised decisions, and leave maximum room for individual innovation;
Oversee the development and ongoing evolution of a national smart electricity system architecture model to provide a transparent platform for integration and innovation, noting the helpful European SGAM developments;
Assist effective technology transfer by which innovation is managed through to commercialisation and deployment;
Assess the adequacy of modelling capability to inform investment and operational decisions, including global trends in software development, and facilitating work to address gaps, particularly for whole-system aspects;
The Institution of Engineering and Technology (IET) – Supplementary written evidence (REI0052)
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Facilitate the adequacy of data access and sharing, data analysis and information systems to support effective whole-system modelling and forecasting, noting the large data volumes that will come from smart meters and active network systems.
Powers and Oversight 13. However delivered, the SA role will need to have appropriate authority to be meaningful. It needs to be empowered to deliver the following:
A sector vision and roadmap, based on a consultative approach with stakeholders across the industry, to provide a shared strategic framework;
A rolling work plan of prioritised activity agreed with sector stakeholders and not duplicating other efforts, using an open governance model;
Foresight of sector technology and engineering developments, challenges and risks ahead;
Alignment of existing GB and EU codes, protocols and guidelines in areas that have whole-system impact;
Engagement in the development of standards, protocols and codes of practice, with a focus on functional rather than design specifications, and on minimising UK deviations from international and European standards;
Challenge to technical, market or regulatory developments that are adverse to the evolution of an efficient overall system;
Impartial and authoritative advice to Government on the engineering feasibility or engineering consequences of policy decisions;
Proactive inputs across government in the event that issues affecting the sector are not being addressed elsewhere, leveraging deep industry knowledge held in industry players - examples might include R, D and D policy, or engineering skills;
Engagement in Europe and beyond, facilitating engagement of other stakeholders;
For effective oversight of the SA itself, agreed performance metrics and accountability under a defined regime for review.
Getting to the point of agreeing the delivery mechanism 14. It is important that the delivery mechanism enjoys the confidence of the industry, and properly balances the complex whole system thinking necessary with the need for the industry to have commercial freedom to operate. 15. Further work is therefore necessary to consider, objectively:
the scope of the activity, building on the above;
a mapping of current activity;
how industry is engaged;
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which elements could be delivered by established industry or regulatory structures, and how;
which elements need new or changed institutional arrangements;
the enabling measures needed;
the risks involved, and how they should be managed.
16. We understand that DECC is considering these issues at the present time. The IET would advocate a thorough objective study using a robust methodology, and engaging the whole industry, to reach a conclusion that would enjoy general support. The IET would be pleased to steer and facilitate this work. About the IET 17. The Institution of Engineering and Technology (IET) is one of the world’s leading professional bodies for the engineering and technology community and, as a charity, is technically informed but independent. This submission has been prepared on behalf of the Board of Trustees by the IET’s Energy Policy Panel and takes into account input received from the wider membership. 23 December 2014
KiWi Power – Written evidence (REI0057)
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KiWi Power – Written evidence (REI0057) Demand Response Turn Down Case Study – KiWi Power and Park Plaza Westminster Bridge London The spectacular Park Plaza Westminster Bridge London hotel is positioned at the entrance to Westminster Bridge in London. The hotel occupies a significant position along the regenerated South Bank's striking architectural and historical landmarks opposite the Houses of Parliament and Big Ben. This 1,019 room flagship hotel is part of the esteemed PPHE Hotel Group and when its doors opened in 2010 was one of London’s largest hotels to open in 40 years. This venue is a successful and stunning example of PPHE’s creative vision to regenerate a key London site and deliver a self-financing, environmentally friendly development. The hotel’s recent partnership with energy technology and demand response aggregator, Kiwi Power, marks another successful step towards achieving their ambitious environmental goals to deliver industry leading sustainability solutions whilst maintaining the highest standards of customer care. The technical solution This hotel offers some of London’s largest and most versatile meeting spaces, including a ballroom for 2,000 delegates, several concept restaurants and bars, an exclusive spa and health club with swimming pool. Its unique configuration of guest services unusually, also includes water bottling and laundry services onsite. Kiwi Power worked with Park Plaza Westminster Bridge London to install meters providing real time electricity readings to help identify energy usage within the site which could be turned down during peak periods and would not negatively impact the guest experience. These assets include:
• 1 x Chiller • Air Handling Unit for the Public areas in the hotel • 3 x Industrial Electric Washing Machines • 3 x Industrial Electric Dryers • Hot Water Primer Pumps
Park Plaza Westminster Bridge London uses a building management system to maintain levels of guest comfort and system activity within the hotel. When the National Grid initiates a demand response STOR programme, KiWi calls upon the property to turn down these assets to pre agreed and tested levels for up to two hours. KiWi’s technology aggregates this rebalanced power supply with other sites to relieve the demand on the Grid. This spares the National Grid calling upon less efficient and polluting solutions to deliver additional energy nationwide.
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Key successes:
Kiwi Power’s meter installation required no capital expenditure investment by Park Plaza and was installed within one month in 2013
Based on time of year KiWi can generate anywhere from 60-300kW's of turn down from this site at each event. These levels would not be enough for them to respond directly to the National Grid, but by working with an aggregator, this generated turn down forms part of a larger STOR programme relieving pressure from the network during periods of peak demand
Since installation in 2013, the hotel has been called upon to turn down for a total period of nine hours. The site has responded efficiently and effectively to each of these requests
In these turn down periods the hotel have delivered 3035 kWh back to the National Grid
Park Plaza’s involvement has provided them with both electricity cost savings as well as additional revenue to put towards other sustainability projects
This represents on offset for the CRC report of 1.5 tons to date
Given the success of this project at their UK flagship hotel, PPHE are progressing with a turn down strategy across an additional six new hotels in the group in London, Leeds and Nottingham.
“When KiWi Power approached us about this project - it was a no brainer for us”, said Devansh Bakshi, Regional Financial Controller UK of PPHE Hotel Group. “KiWi installed their proprietary technology solution which remotely accesses and reports real time energy usage data. This data itself is extremely useful information in our reporting commitments and will help inform ways we can positively impact our energy usage and drive sustainability on site. “Working with KiWi makes this process easy and has been a great success for us. By participating we’ve not only reduced the carbon footprint but saved energy costs by reducing our consumption for brief spells during Grid peak time. These savings and earnings will go straight back into our business and allow us to invest in other sustainability initiatives. “We’re pleased be able to demonstrate such measurable, tangible results and to know we’re having a directly positive impact on the environment. This not only pleases us but our guests too. We’ve received some very positive press coverage for the work we’ve done with KiWi which has been great in attracting visitors to our hotel and in spreading the word about our commitment to corporate social responsibility.” About KiWi Power KiWi Power was co-founded by Yoav Zingher and Ziko Abram in 2009 and is a smart grid energy technology company and demand response aggregator. Combining proprietary hardware and software and best in class teams KiWi Power delivers significant commercial returns and sustainability benefits to large consumers of electricity, utilities and grid operators. Demand Response is a unique and powerful application using technology to reduce electricity consumption at peak times across industrial and commercial sites. This creates a
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greener, more cost effective grid; reduces the need for inefficient backup power stations and provides vital balancing requirements and security of supply to system operators and end user sites. KiWi Power’s innovative approach is leading the way in evolving the UK demand response market as well as influencing the design, build and operation of demand response programmes around the world. KiWi have been instrumental in setting up new demand response programmes with distribution network operators including UK Power Networks (UKPN), Northern Powergrid and Western Power Distribution. Kiwi’s enviable and diverse industry portfolio of 50+ clients across 650+ sites includes some of the UKs most well-known brands including Marks & Spencer, the NHS, Park Plaza, Marriott, Trinity Mirror Group, Ocado and Scottish and Southern Energy (SSE). 6 February 2015
Llinos Lanini – Written evidence (REI0005)
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Llinos Lanini – Written evidence (REI0005) Real Time Demand Grid Monitoring and Automated Demand Response in relation to the House of Lords Science & Technology Select Committee’s inquiry into ‘The resilience of electricity infrastructure’. We are addressing Medium term (to 2030) issues now, especially such matters as developments in technology that are game changing, the possibility of reducing the cost of maintaining resilience, addressing the greenhouse gas emission crises and creating jobs for the UK economy. Our Company, Iviti Lighting Limited has developed Real Time Demand Grid Monitoring technology which we call 'Automated Demand Response' (ADR). The invention, design, testing and manufacturing is all U.K. based. What is it? Real Time Demand Grid Monitoring software, inside (or outside for retrofit) an LED light source that can immediately, automatically and undetectably switch itself to being powered by its own internal battery. When an electricity Grid’s System Frequency drops below a certain value, indicating that it is under pressure, the light source automatically, immediately and undetectably transfers its power source from the Grid to its own internal battery. When the Grid's System Frequency exceeds a certain value, which is in effect 'wasted' energy, the batteries can be fully re-charged. Further logic is incorporated into the technology to take advantage of the cost savings which can be obtained by not using Grid energy when the tariff is at its highest price and switching to battery operation during these times irrespective of Grid pressure. This will result in major cost savings to the user, and in some cases the electricity saved can be sold back to the Grid. This technology is unique within the lighting industry and because of its very high speed of response, can reduce the need for a Grid to call for back-up power from the expensive, older, dirty, coal fired generators etc during peak demand times, thereby reducing greenhouse gas emissions and saving money. In addition, the light source incorporates technology that detects a power cut which then automatically triggers the light source to switch to battery operation and can last for up to 3 hours. The battery is charged when the power is back on. This is a truly innovative tecknology, covered by IPR in Europe, USA, China, South Korea and Japan. It will also be a truly global product especially in those countries where Grids are unreliable. This will create more jobs. Please contact me for further information. 18 August 2014
Dr Keith MacLean, University of Exeter, Professor William Nuttall, Open University and Professor Jon Gibbins, University of Edinburgh – Oral evidence (QQ 91-101)
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Dr Keith MacLean, University of Exeter, Professor William Nuttall, Open University and Professor Jon Gibbins, University of Edinburgh – Oral evidence (QQ 91-101) Transcript to be found under Professor Jon Gibbins
Professor Catherine Mitchell, University of Exeter and the European Network of Transmission System Operators for Electricity – Oral evidence (QQ 139-149)
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Professor Catherine Mitchell, University of Exeter and the European Network of Transmission System Operators for Electricity – Oral evidence (QQ 139-149)
Evidence Session No. 12 Heard in Public Questions 139 - 149
TUESDAY 9 DECEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Baroness Sharp of Guildford Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston
______________________
Examination of Witnesses
Professor Catherine Mitchell, University of Exeter, and Dr Konstantin Staschus, Secretary-General, European Network of Transmission System Operators for Electricity
Q139 The Chairman: I welcome Professor Mitchell and Dr Staschus. I apologise that we are starting a little late, but I know that you have had some challenging travel arrangements to get here, so perhaps you have had time to catch your breath. Could I ask if you would like first of all to introduce yourselves for the record? If you would like to make an opening statement, please feel free to do so. First of all, would Professor Mitchell like to introduce herself?
Professor Mitchell: Yes. I am Catherine Mitchell. I run the Energy Policy Group at the University of Exeter. I think we will just go straight in, for me.
Dr Staschus: My name is Konstantin Staschus. I am the Secretary-General of ENTSO-E. ENTSO-E is the European Network of Transmission System Operators for Electricity. It was established in 2009 following the adoption of the European Union third internal energy
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market package, which prescribes in one of its regulations that all the transmission system operators in Europe need to be members of ENTSO-E and work together to do joint, Europe-wide, 10-year network development plans and to draft network codes related to technical and market conditions for co-operation across borders in the European electricity market.
The Chairman: Thank you.
Q140 Lord Broers: This is the very general and important question. How does electricity resilience in the UK compare to that in other countries in Europe and North America, and are the UK’s current and projected capacity margins lower than in the other countries? How does the resilience of transmission and distribution networks in the UK compare? Dr Staschus, you have the good European viewpoint.
Dr Staschus: Yes. If I may, let me start with a general remark about the growing importance of electricity transmission and electricity interconnection with respect to resilience, growing as the European Union in general and the UK in particular are trying to reduce their carbon dioxide emissions from electricity generation and from the energy system in general.
There are of course different kinds of generation resources that are being pursued, but one very important kind is renewable energy, and especially among the various kinds of renewable energy, the less expensive ones compared to some others like wind energy and solar energy. Both of these operate only when the wind blows and the sun shines. In many parts of Europe, for wind, that is then in the neighbourhood of 20% to 30% of the time. That has a very important implication for the need for interconnections, because if you want to supply a lot of energy with wind energy, for example, then you need to install quite a bit more wind energy capacity than even your peak load, maybe, which then means if there is no wind, you tend to have too little electricity, and if there is a lot of wind, you tend to have too much. That is where the strong European grid comes in, because over a relatively large area like Europe the wind conditions differ in different parts of Europe at the same time, so the parts of surplus have some probability of being able to export to the parts of deficit.
When we are doing our transmission planning studies on a European basis, we find that much of the economics and 80% of the projects Europe-wide are driven at least partly by renewable energy integration, and the economics of that and our economic studies for that work out largely along those general principles I have been trying to describe. A strong grid is one of the best ways to keep resilience up as you are investing more and more in renewable energy, and to keep the overall costs of the electricity system affordable to consumers.
Finally, coming to your original question, of course with Great Britain being an island, the situation of the interconnections is not very strong so far. Towards the continent, that is 3,000 megawatts, and that is relatively low in comparison in terms of interconnection capacity to the countries on the continent that have it easier because they have many neighbours on land.
The interconnection is of course only part of the resilience of the electricity system. The electricity market in Great Britain—England, Wales, Scotland—is already quite a large market with quite a bit of diversity, and it is managed very well in comparison to other parts of Europe with respect to the market arrangements, the duties and the tools that National Grid has at its disposal to keep the system balanced and so on. From those perspectives, focusing on Great Britain alone, it is a very positive picture. If you look at the increasing importance of interconnectors for the future as more and more renewable energy comes
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into the system here and elsewhere in Europe, more interconnection will have to be built to keep the transition towards low-carbon resources affordable and as resilient as possible.
Professor Mitchell: If I look at it in a slightly different way. I think one issue is that thinking about capacity margins in terms of a per cent is changing. When it was a fossil fuel and nuclear-dominated type system, one tended to think that you needed to have a certain percentage over and above a certain capacity. As we are moving into a much more integrated and flexible system, I do not think you should necessarily think about things just in that way. You need to think about how much storage there might be in the system or how much demand for flexibility there is or what the interconnectors are.
Then, just turning to the US, the type of codes and licences that most of the 50 states in America have—given you can find any type of electricity system in America in the 50 states—in general the system standards are very similar. One way that the US is far better than all of Europe is to do with demand-side response within markets. Pennsylvania, New Jersey and Massachusetts—PJM—is a market that has bits of 13 states and covers 51 million customers, which is about the size of Britain. I just have this quote for you so that you see the picture. The demand response in that market is able to compete in exactly the same way as supply, so it goes into the same market. For 2010, which was for capacity in 2013-2014, it saved those 51 million customers $12 billion and it paid the equivalent of £430 million, or 10 gigawatts of demand side response. That is in PJM. That is about 12% of projected demand. You bid in to not use it, rather than to supply it. If you have a flexible demand system, then when you have issues of capacity or resilience problems, you are much more able to deal with it, it is cheaper for customers and it is better for security. PJM is the best. That is about 12% of demand roughly, but the average in the US across those 50 states is still 6%. If you look at our system here in the UK, which is a market-wide system, it is about 1% of demand and you cannot bid in in the same way. It is a very poor system in relation to that.
Q141 Baroness Manningham-Buller: Can I just pick up one particular point, Professor Mitchell? You compared Europe to the States, in this particular respect. Are there countries within Europe that are better than we are at handling this?
Professor Mitchell: Not really. We are all trying to think about how we start to bring the demand side into markets. Germany, Denmark, Italy, Spain, all these places are beginning to do that, and I think that they will become better than us. We have just started to do it through EMR, and I would hope that we will learn and grow and become better. Actually, DECC says that it wants to do this. It is just that the system that it has been put in place is something called a market-wide system, which is very inflexible. It is almost the opposite of what you want a demand-side system to be.
Baroness Manningham-Buller: One of the things this Committee is looking at is where we can learn from other people in the world, and you have given us the example of the States. Dr Staschus thought we have a pretty good system here. Could I ask you in terms of carbon emissions, intermittency, percentage of renewables used and so on the question you have already seen in advance: where can we learn from our friends in Europe as well as from America? I cannot believe we are ahead of everybody.
Dr Staschus: Learning within Europe on the precise issue that Professor Mitchell just addressed would probably best focus on those countries that have already rolled out smart meters to their household customers. Italy was first, but then very notably there are also the
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Scandinavian countries, for example Sweden and Finland, which have made progress on that. That enables the demand also of household customers to somewhat flexibly react to developments in wholesale prices.
I would like to differentiate two effects here. One is where the customer, through his own choice and action, but perhaps also through home automation or smart homes, decides to react to price developments, and of course he has to have the prices there visible to him or to his software. That is the case for industrial customers, for large commercial customers and, in the future, with smart meters, that should be the case for household customers as well. This kind of flexibility we believe is very important.
Then what Professor Mitchell was mentioning was actual bidding systems, where the customers of various sizes react to auctions for especially flexible capacity or especially flexible demand. These are auctions that usually the transmission system operator, perhaps also the distribution system operators, would be running. Then there needs to be some verification schemes, but if those are in place—and to the best of my knowledge they are in place in the United States—these can compete on an equal basis with generation resources to deal with fluctuations in renewable energy input and keep the system stable. In fact, as Professor Mitchell was mentioning, to the best of our knowledge these demand flexibility resources can compete quite well in terms of costs with generation flexibility resources. The Nordic countries would be a good place to learn from.
I want to mention, if I may, a second kind of learning, which is institutionalised through the internal energy market procedures we have in Europe. I mentioned in my brief introduction that ENTSO-E has the privilege of drafting network codes that are supposed to cover all cross-border aspects of the market functioning Europe-wide, so for consumers, people that exceed 500 million. In these codes we try to look to the future and set conditions that support demand-side response, which support flexible generation resources and which make sure that both demand and generation act, during some instability in system operation, in such a way that they support the stability of the system and do not make it detrimental.
Among the 10 network codes that we have been drafting, there are three that relate to how the market functions. We are trying to set all these conditions in what ends up being hundreds of pages of the three market codes in such a way that the demand-side flexibility is supported but the overall resilience of the system is made as strong as possible.
When our members, 41 TSOs from 34 countries, sit together and draft these network codes, their experience from the frontrunners in renewable energy integration flows into the overall discussion. The Irish in their small system might have a system inertia problem, too few rotating machines, with the mass keeping the system stable, so we benefit from their experience with that particular island-related problem, which might hit the rest of Europe later. The Germans have 75,000 megawatts of renewable energy capacity roughly today already, compared to their 80,000 megawatt peak load. That is an awful lot, so they have more experience than the UK and many other countries in how these enormous amounts of renewable energy can be integrated into the system. When we write the network codes, this sort of experience gets integrated in what we write into them.
Professor Mitchell: Yes, I agree. I think you need a very strong transmission system throughout Europe because of flows, but transmission is just one part of the energy system. Essentially what is happening is that over the last 10 to 20 years we now have a completely
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new set of technologies. We just heard about the rapid change in terms of solar. But the really big one is the ICT, which is now used to operate and manage the systems, so you can manage systems in a completely different way than you did before. The old system, where you had a big power plant and the electricity essentially went down through the system to the customer, is how our markets and regulation works and links to those old technologies, but in fact the energy system is made up of completely different technologies that have completely different operating characteristics. The problem is that this old system fits the rules and incentives and these new technologies have to fit into that system. I think that is where the problem of resilience is.
Baroness Manningham-Buller: It would help the Committee if you could give us a clear idea of what recommendations in that area you would like to see us make.
Professor Mitchell: I think that you need to rethink the role of the regulator, the role of utilities and the role of customers. For example, New York State, which has 31 million people, has something called Reforming the Energy Vision, and that is an example of a large state—that obviously has huge, important industries based in New York City—that is trying to do that. Minnesota, Texas, California: all these states in America are trying to take this very solid base of codes, licences, economic regulation and so forth and drag them into being able to meet the needs of new technologies. An example I give for this, and forgive me if this is too simple—
Baroness Manningham-Buller: We like simple. We have very little of it.
Professor Mitchell: If you think 20 years ago we were based on landline telephones and telephone boxes, and then we moved into mobile phones and all you could do with your mobile phone was talk to somebody on it, I would say that is where British economic regulation for electricity is. Then if you think about phones now, the “speaking to” bit of a phone is just one very small bit of what a phone does. You have maps and internet and all these kinds of things. The reason why we have smartphones, which we can do so many things with, is a combination of competition and of regulation.
In energy, we have all these different technologies that allow us in theory to run a system very effectively with far less energy. The stuff that Kevin Anderson was talking about, about these mega-systems, I think is entirely unnecessary. If you get the competition bit right and you get the regulation bit right so that you effectively have your smart energy system, like you have your smartphone, then I think you end up with a cheaper, more secure and altogether more resilient system. It is rethinking the way that we think about energy. However, our energy system is still at the equivalent of the simple mobile phone rather than the smart phone stage. That is not to say that Ofgem and the department are not trying to do that, but of course they are in this situation that they have to go from one to the other, and that has huge distributional impacts about how you do that. If you go down one way compared to going down another way, then that suits one sector versus another sector, and it is obviously not as easy as I have said it. As I say, many states in the US are now beginning to think like that.
Q142 Lord O’Neill of Clackmannan: I have been listening to Catherine Mitchell talking about the American model and comparing it to the UK one, but is there not one fundamental difference that in the UK there is clearly an attempted competitive market, whereas there
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tend to be local monopolies in the US, and there is not quite the competitive model that we have in the UK to compare it with? Do you think that makes a difference?
Professor Mitchell: There are 50 states. Seventeen of them have competitive markets, competitive retail markets, so you have several that you can look at.
Lord O’Neill of Clackmannan: Have any of them been the ones you have quoted to us this morning, like the PJM?
Professor Mitchell: Yes. Absolutely. All of those that I have talked about are the competitive markets.
Lord O’Neill of Clackmannan: Fine. Thank you.
Professor Mitchell: There are real differences between any electricity system in any country, and you need to always design your electricity system or your energy system to meet that country, but there are so many examples of just sensible practice around the place that I think it is easy to be able to bring those back from the US or, say, from Denmark. Somebody was talking about heat pumps, for example, and heat pumps can be incredibly inefficient if you use them singly, just because of the technical thing. It just happens in Denmark that people tend to live in these apartment blocks and some times they have loads and loads of wind. Sometimes they have 160% of their electricity demand needs. So what they do is that the extra 60% effectively goes into their heat pumps and it acts as storage. That is absolutely brilliant for Denmark. It is not something that would be able to work in Britain. But if one learns from other countries then you can start to pick and mix so you can get a system that totally suits Britain.
Lord O’Neill of Clackmannan: Dr Staschus?
Dr Staschus: Yes, I wanted to latch on to some of the things Professor Mitchell just said. I used to know the US market pretty well because I lived there for 14 years when I was younger, including nine years of work at Pacific Gas and Electric, one of the bigger utilities over there, but that was 20 years ago. I am still trying to follow it, and indeed we have good contacts to PJM. The numbers Professor Mitchell just gave tell an interesting story. Out of 50 states, 17116 have a market in the US, and a large number do not. They indeed have the old monopolies, as you were implying. It is a bit unfortunate that the US has not been able to agree nationwide for their 350 million inhabitants on a common model for how they want to arrange their electricity industry. Thanks partly to the UK’s forerunner role back in the 1980s and 1990s, Europe has embarked on what I find an amazingly strong consensus that market solutions are the right answer for how to arrange the electricity industry, and the same kind of basic market arrangements all across Europe with 500 million people is the right answer.
From my personal perspective, one aspect of having market solutions is not to be underestimated at this time, and this is the innovation that comes from, for example, a big price drop in photovoltaic panels over the last five years, and the innovation that Professor Mitchell mentioned with respect to better usage of information and communication technology in order to make our homes smarter, in order to make our grids smarter, in order to be able to use storage solutions locally or Europe-wide. All this innovation from our perspective can best prosper within the market environment and not in a monopolistic environment like many parts of the southern US still have.
116 This figure may be higher reported by Dr Staschus after the meeting.
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We try to plan the transmission grid and analyse each new interconnector with respect to costs and benefits in a multi-criteria way and with respect to the greater uncertainties that we foresee in the future. It is very hard to estimate, for example, whether the photovoltaic cost decreases that we have seen over the last five years will continue, and if so, at what pace they will continue, and how cheap photovoltaic power will be even in the year 2020 or 2025. It is also not so easy to estimate how much demand response there will really be from the households. If they have a heat pump, there can be a lot of responsiveness, but not everybody is going to have a heat pump. Not everybody will have an electric car within the next 10 years. If one does not have these large demands within the household, then the benefits from smart meters might be quite a bit less.
We try hard to send each of the 120 Europe-wide transmission projects through a very demanding cost-benefit analysis, with hour-by-hour simulations of the year 2030, in four very different scenarios: one that has lots of renewable energy, lots of demand response, and will almost certainly need strong grids and also very smart grids at the distribution level; and another scenario at the other end, which is quite conservative and does not have anywhere near as much renewable energy, not anywhere near as much innovation in the distribution grid, and then you will need less transmission lines. Even in that conservative scenario, you still need roughly twice as much interconnection Europe-wide as you need now. The two big spots where the biggest investment is needed are Germany, with all the renewables they already have, and the UK, with the interconnections to Norway, Denmark, Belgium, Holland and France that would make the market in the UK much better integrated. If the wind blows well, in the future, with a lot more wind energy in the UK than today, the operators of those wind parks can still get a decent price for their wind energy in other parts of Europe that they are exporting it to. If the interconnections are not there and the wind blows well and you have installed a lot of it, you need to curtail it and you do not know where to put it, except perhaps in storage, which today is still quite expensive.
Q143 Lord Peston: I got a bit lost on the difference between market and non-market solutions, and I would like you to clarify. If you are in America, there are some states, I gather, where there is only one supplier and they really have a monopoly. That is right, is it not? I must say, when I lived in America I had not the faintest—
Professor Mitchell: You usually have area-based suppliers, so in the area that you live.
Lord Peston: But you could not switch?
Professor Mitchell: There are different companies. No, but you cannot switch. That is as domestic customers. There is usually retail competition for bigger customers everywhere.
Lord Peston: Let us concentrate on domestic for the moment. As an economist, I would define a monopoly as a single supplier.
Professor Mitchell: Yes.
Lord Peston: If we then compare with Europe, typically how many suppliers can a household choose between in a typical European country?
Professor Mitchell: I think Greece is the only country now where domestic supply is with one company.
Lord Peston: If you live in Germany, how many companies would you be choosing between?
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Dr Staschus: In Germany, most cities might have around 30 or 50 different—
Lord Peston: Fifty producers of electricity?
Dr Staschus: Yes.
Professor Mitchell: Producers or suppliers?
Dr Staschus: Suppliers.
Professor Mitchell: Yes, so that would be someone you buy from.
Dr Staschus: Also, keep in mind that several countries put a lot of emphasis on municipal utilities. In Germany you have 800 municipal utilities. Some of them are big enough to be active on the nationwide market. Also, some other countries have municipal utilities and if you abstract from the municipals you might, in many countries, have five or 10 offers. I am sorry that this is not exactly my field of expertise, how many there are.
Professor Mitchell: In Britain we have, I think, either 23 or 27. We have the big six, and then you have a number of other small suppliers.
Lord Peston: The fact that I do not know the names or how I get in touch with those other than the one I have means that I am genuinely in a tiny minority.
Professor Mitchell: Yes. I think you are with EDF, actually.
Lord Peston: Everybody else in this room knows the names of 20-odd companies they can go to.
The Chairman: We will give you the address of the change website.
Professor Mitchell: I think it is an interesting fact—
Lord Peston: No, the fact is that I am not convinced of this. The point I am trying to make is I am not convinced of the market versus the non-markets.
The Chairman: We had better move on.
Lord Peston: I have made my point, I think.
Professor Mitchell: I think an interesting point, though, about that is that there is no easy way for you to undertake a comparison. I think Ofgem should have on their website a comparison, because there are many comparison sites but they are comparing different things and often being paid for by companies on those sites. Having a good comparison site that Ofgem sets a template for would be absolutely brilliant for customers.
The Chairman: Comparison is extremely complicated.
Q144 Baroness Sharp of Guildford: In many senses we have covered the question that I was due to ask, which was about capacity markets, but there is one remaining from it that I would like to ask, which is: if Professor Mitchell is right in saying that we are using, in a sense, the methods that are now a decade old or more than that, does this not have very serious implications in terms of the choice of infrastructure that we are now due to make? This is a very real problem because if we are going to in a sense install an infrastructure that is much less flexible than the way the market is developing and the need to have this enormous flexibility, as you were saying—things like the development of solar on the one hand, or heat pumps on the other—the microgeneration issue perhaps is not at the moment captured within the model that DECC is using.
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Professor Mitchell: I agree. I should say that Margaret was a role model for me. I used to work with her in my very earliest stage a long time ago.
Can I just say two things? One is about the capacity market that we have in Britain, and the other is about the innovation side of things. The capacity market that we have in Britain now is a market-wide system, which simply gives money because they are there. It is not asking them to do anything about their capacity, their capabilities or what makes the system more flexible. It is a very poor system, and I have written on that. I am very happy to send stuff in to you if you want to have more on that.
Because it is the kind of system it is, it is not supporting flexibility. Really what you need in this rapidly changing world is a combination on the one hand of an overseer, some kind of framework that is trying to keep everything together, and flexibility around the edges so that you can keep up with these enormous changes that are going on. I like the Energinet model in Denmark, whereby Energinet is a system operator. It is a state-owned system operator. It has been given the responsibility for security and for transition, the transition to the low-carbon system. You have something that is technically able to keep track of what is going on, and at the same time the changing rules to do with codes and licences and all the rest of it feed into that. That seems to me to be a way that keeps the flexibility to whatever might suddenly happen and at the same time ensures security. Unlike having the GB market-wide payment, what the targeted strategic reserve mechanism is what most states in the US do or what many places in Britain do. If they feel that they need some more capacity of some other capability requirement, Energinet the system operator, is able to say, “We need 300 megawatts of this”, and then that can be competitively put out to tender if you need it. Then, if you do not need it, you do not have to tender for it, whereas our capacity mechanism is just based on giving out this money, even though things change all the time and it may be completely unnecessary, and it is the customers who pay in the end.
Baroness Sharp of Guildford: Would it be possible for you to do a short paper on that and let us have that?
Professor Mitchell: Yes. I can send that.
Q145 Lord Willis of Knaresborough: May I ask Professor Mitchell and indeed Dr Staschus a simple question? I was particularly interested in this issue that you brought from the States about demand as a market lever. Could I ask this question? If in fact demand becomes a major market lever—and 12%, as you were talking about, is a very significant market lever—would there be sufficient resilience in the current interconnector system to avoid you having to increase significantly base load capacity?
Professor Mitchell: The situation about interconnectors is, I think, incredibly interesting. Somebody was asking about the cost of electricity in Europe. We are middle-ranking in terms of our retail price of electricity, but if you look at our wholesale price, I think there are only two or three countries, Cyprus and somewhere else, that are higher than us. We have very high wholesale prices. One of the reasons why we have very high wholesale prices is that, I think, 2% of our total capacity is interconnected, and the Commission wants to have roughly 10%. In my view, and I am sure many people would say it is very simplistic, I think it has been in the interests of the large generators in Britain not to have interconnectors, because if you were to have interconnectors then cheaper electricity would come in from the continent.
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The regulation of the way that we fund our interconnectors has always been that it is a market system based on the interconnector itself, as compared to the whole of the rest of Europe, which sees interconnectors as part of the transmission system. So they go along to their regulator, their regulator says you can have the money to do that and then they socialise the cost of the interconnector over the cost of electricity. We have now been forced to go down a third way because our British system has not fitted with the European system, and now we have some fudge between a market and a regulated mechanism.
Overall, this is part of the issue that I am talking about. We have a set of regulations that are based on older technologies and we need to move into regulations that fit the world that we live in. We need to sort out our interconnectors in order to do that and at that point, if we were to go up to 10% of our supply with interconnectors and being able to move power around, which is good in every way, then yes, obviously you do not need to have what would have been 10% of generation, absolutely.
Dr Staschus: Could I add a few thoughts to that?
The Chairman: Yes, please.
Dr Staschus: Relating to the role of Energinet.dk in Denmark, they are the TSO identified by the Danish Government, just like National Grid is the TSO identified by the UK Government for Great Britain, and they have very similar roles. The transmission system operators in all of Europe have been unbundled in three waves (i.e. in the three EU Internal Energy Market legislative packages). As I mentioned, the idea originally came from the UK, and Europe has largely copied that, along with other parts of the world, where if you want to have competition in electricity the only way to get the power from a competitive producer to any customer is through the grid. So the grid has to be neutral, and that is why it needed to be unbundled in the past decades from the interests of supply and from the interests of generation in particular. That has happened all over Europe in ways that are rather similar to each other, even if not entirely identical, and that is why then the TSOs here in the UK and in Denmark and elsewhere have very similar roles: keep the lights on, first and foremost, and facilitate the market functioning, and support the energy policy goals.
If the energy policy goals in all of Europe and in the UK say, “Decarbonise as much as you can the electricity sector”, then that becomes—I know that is the case in the UK—a big objective driving the regulator, Ofgem, and it becomes a big objective driving the TSO, National Grid, just like in Denmark. That is why the transmission system operators believe and try to prove through cost-benefit analyses that, under different future scenarios, transmission helps to keep the transition to a low-carbon future affordable. That is why they also strongly support the introduction of more and more innovation and smarts into the distribution grid and into the interactions of the customers with the market.
We do not talk often about the smart transmission grid because we like to think that it is already very smart. Every two or three seconds measurements from the entire system come together in the control centre and get used to keep the system resilient. They get used, as National Grid I believe explained to you already, to make simulations for the next minute and the next hour to make sure that whatever happens in the grid—a line going out because of a storm, a power plant having a forced outage, whatever single thing happens—will not lead to an overload on any part of the system and will not lead to a blackout.
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Some of the network codes I mentioned earlier are describing, based on the best practice Europe-wide and the best anticipation of the challenges of the future with more renewables, how precisely to run the software in all the control centres in Europe so that also we avoid the situation in which one with less optimal processes becomes a blackout risk for their neighbour, even if they may have better processes.
Can demand-side response avoid base load capacity? We feel that is another reason why our 10-year network development plans might be useful to policymakers, political deciders like you, but also to the market participants, because we try to open up a broad range of scenarios of how the future might develop and then show through the precise simulations how the market prices are in this future and how they fluctuate from one hour to the other.
If there are more and more renewables, the market prices will fluctuate a lot and there may not be so many of what we call base load hours left because, once you subtract from the load the generation coming from zero-operating cost renewables, you may, in some or in many hours, have very little left. That is why the economics of base load generation have been changing slowly throughout Europe. Our 10-year network development plans try to give a picture of how this would look in the different scenarios with the foreseen amount of base load generation and the foreseen amount of renewables. But I would strongly agree that demand-side response is a necessary ingredient to keep the system manageable.
Professor Mitchell: Can I just say one thing about that? The thing about Energinet is that it is state-owned. It is not a private company as National Grid is here so there is a difference of ownership first of all. Security is placed on them as a responsibility. It is not part of the market as it currently is here in Britain. As Energinet has been given both security and transformation as their responsibility, it gets rid of this incredibly unhelpful competition between transmission and the distribution network operators. That is why I like the Energinet model. I agree that there are all these transmission companies all over the place but, depending on the responsibilities that they are given and their ownership, they are very different animals. It is that particular sort of characteristic that is so good about Energinet going into the future, because it enables appropriate choices to be made to run this system most efficiently rather than this differentiation between DNOs and transmission.
Q146 Lord Patel: My question relates to electricity prices in the UK and the rest of the EU. To a degree, Professor Mitchell, you answered part of the question about electricity prices being higher in the United Kingdom. What do the other countries in the EU look like for electricity prices?
Professor Mitchell: For all the questions that you asked me, I looked at the websites for all the answers.
Lord Patel: Maybe we could have those later.
Professor Mitchell: Yes. You can see this set of average wholesale prices and then the additional taxes and levies on top of that. If you add the lot together then Britain is in the middle of all of these electricity prices. If you just look at the wholesale price, we are near the top and we have very little in terms of levies and extra bits on our prices.
Lord Patel: How does that reflect in consumer prices?
Professor Mitchell: In terms of consumer prices, the retail price, we are in the middle, roughly. There are two things going on. First, if there were more interconnection, then prices
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would come down and that would also be more secure. Secondly, there is this issue about variable power. If you are in a country with a lot of variable power, because markets are based on marginal costs, it takes the zero marginal cost electricity first of all, so it takes the renewables first and that shunts over the more expensive fossil fuel stuff. It just moves over the supply curve to the right. So fossil fuels, which have higher variable costs, will not get into the market any more. That is one thing, but the other thing is that often that variable renewable generation happens at the time of peak prices and because it is zero marginal cost, those peak prices come right down. That is why countries with a lot of variable power have much lower wholesale prices.
At the moment we are subsidising renewables, but once that subsidy has gone then you basically have the zero price marginal cost electricity, which is the goal of the innovation policy. When you have a marginal cost market, which tends to happen every half hour, you pay the price for that half an hour for that last bit of electricity you have bought in a traditional market, so absolutely all electricity used in that half hour is paid that high price. If, all of a sudden, you have more and more variable power and you are bringing down your peak price, then it is not just that your peak price is coming down but you are also paying a whole lot less for all the electricity as well. On the whole, as you are getting more and more variable power coming into the system, you are going to end up with lower wholesale prices.
Lord Patel: Why do some countries end up having higher taxes? Denmark, Germany—
Professor Mitchell: Germany is a really good example of a country that is just getting to the point where all the higher costs that it has added to electricity wholesale prices, not just for renewables and energy efficiency but also environmental things, are starting to come to an end so that it is moving into lower overall wholesale prices. Those extra bits that some countries are putting on will be, on the whole, to do with environmental levies or whatever it might be.
The Chairman: Lord Broers, do you want to come in? I am sorry, but we are running a bit late so we will keep it short.
Q147 Lord Broers: Just a quick question. US electricity is half our cost, both domestic and industrial. We are lower than Germany although the German generation cost is slightly lower.
Professor Mitchell: Yes, wholesale, that is right.
Lord Broers: What are the Americans doing? Is their electricity producing much more carbon? A factor of two is huge and for industrial companies it is a massive disadvantage. It is a massive disadvantage that Europe is setting itself against America. I think we have to try to understand that a bit.
Dr Staschus: If you compare especially industrial electricity prices, they will have a relatively smaller network component in them because they are connected at higher voltage levels and the higher voltage levels per kilowatt hour are relatively cheaper than the lower distribution voltage levels. So the wholesale price becomes a much more dominating part of an industrial electricity price than it is for household customers, where there is a lot more network fee. Some of the countries are trying to keep the renewable energy subsidies, to some extent, as far as is legal within the EU, away from the industrial power prices to at least keep them as competitive as possible. So comparing US and EU or British industrial customer electricity prices, they are dominated by the wholesale market price and, if your gas is a lot
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cheaper, as it is in the US now because of the shale gas than it is here in Europe, then the overall generation cost in the US ends up being cheaper, almost by necessity, than it can be here.
Lord Broers: It just seems the same when you look at it. The ratio is the same and presumably we can do the same thing. We can supply large users at higher voltage, can we not?
Dr Staschus: You do, but you do not have the cheap gas here, as they do in the US.
Professor Mitchell: I think it is a combination of things. It is partly resources. It is partly that they have something called public utility commissioners whose job it is to keep track of prices to customers. It is a sort of hybrid method, so although we would call it competitive in the sense of retail, every time anybody wants to sell to a customer they have to go through the public utility commissioner and that means that there is a very close look at the need a generators say they need to have another power plant. That is why the demand side is so much bigger in the States.
But it is also a combination of the pool. You have a different electricity market. You have different sorts of regulators that keep much closer track of prices to customers and, because of that, you have far better demand side. It goes back to this point that I was talking about: if you lower the peak price, that also reduces all the price of electricity in that half hour. The demand side response routinely brings down the price of electricity in that half hour by two-thirds or something like that in PJM. You know I gave that example of $12 billion saved? This derived from bringing down the peak price by two-thirds. The demand side is not just about creating more resilience; it is causing the whole price of electricity for that half an hour to come down as well. It is this combination of methods, which is why—given this complexity of the system now with the needs of climate change but also all these new technologies—we really should be rethinking the role of the regulator, the role of utilities and the role of customers.
Q148 The Chairman: That brings me to a question about EU regulation. You have given us some fairly firm advice that the regulators, not just in Britain but in Europe, should be trying to embrace the new technologies and develop the opportunities that other parts of the world seem to have done quite successfully. What is it that you would expect of the EU regulator if we are to achieve a greater resilience and to be able to capture some of these obvious benefits that you demonstrated elsewhere?
Professor Mitchell: I am fine about the way policies work, but I quite like the idea of a European regulator, a transmission regulator, like FERC in the States. What would you think of that?
Dr Staschus: There is already the Agency for the Co-operation of Energy Regulators, ACER, which has been instituted in the same internal energy market package of 2009 when ENTSO-E also was founded. They do what their name implies. They try to co-ordinate the various EU national regulatory agencies’ work so that it fits together EU-wide. They provide a lot of opinions and some oversight over the ENTSO-E work, but they also try to find consensus among national regulators when it is difficult. You may, for example, have transmission line projects that cover at least two or sometimes even three or four countries. Think, for example, about the North Sea offshore connections that will go among different countries through the middle of the North Sea. The regulatory details can differ quite a bit from one
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country to another and that may make it difficult for them to agree among themselves which part of the cost of such a subsea cable might need to be charged to the Belgians, the Dutch and to the British customers. If and when they do have trouble agreeing on something important like that, which can even block an investment if you are not careful, then that agency in Ljubljana can step in and hopefully bring them to a consensus.
My members in ENTSO-E, they are the regulated companies. Each one of them is subject to very important regulation in their country on tariffs, on procedures, on congestion management and many other things. We have been calling in international fora in Europe for a strengthened hand for ACER, for this regulatory co-operation agency, because we feel that the international co-operation needs to improve if we want to keep a low-carbon system affordable to the consumers for the reasons I have mentioned. International co-operation cannot prosper as well as it should if the regulators cannot agree with each other, so this function of making them come together more, agreeing more, is very important for us.
Q149 Lord Patel: This relates to research. Very quickly, who in Europe is doing research into new technologies to maintain resilience in the future and what contribution is the Horizon 2020 European programme making towards this R&D?
Professor Mitchell: I do not know about that. My view is that learning by doing is the best way forward. Those countries that start to do things and then learn on the job are the ones that show innovation.
Lord Patel: Which are they?
Professor Mitchell: Germany and Denmark probably but also Italy, Spain as well, to a degree. The thing about Britain is that Britain is good theoretically. We are terribly proud about finding out the problems before we do anything at all but then we do not actually do anything at all. We are just theoretically good at it. I am sure that is true and I would not just say that.
Can I just go back to having a strengthened European regulator? I support that but I also support a smaller regulator in member state countries. We have Ofgem, which is the economic regulator, which essentially is responsible for everything. It makes much more sense that that member state regulatory role becomes much smaller, as in Denmark in combination with a member state system operator that is responsible for transmission and security and so forth. Then you have a European-wide regulator. You will run into problems if you have a strong country member state regulator and a strong European regulator. It is good to have a strong one at a European-wide level and for the state regulator to have a different function—this is part of this whole thing of rethinking the roles of all these people—which, again, fits very much with the Danish model.
Dr Staschus: I know we are out of time but we have two documents that I would like to send your clerk for the record, one addressing the question of fostering investment in the grid as a function of how it is regulated—so that is the question of just now—and another one that gives data about next winter’s resilience in the power system, country by country, week by week.
The Chairman: We would be very grateful for those two documents but also the information that Professor Mitchell referred to earlier. You have brought some answers about comparative costs between countries that we would be very interested to hear. If you were
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able to give us your further thoughts about regulation and the relationship between Europe and national countries, I think that would be very helpful. I am conscious that we have had to curtail some of the discussion on some interesting issues that we could have discussed in much greater depth had we had the time. As it is, I am afraid we have impinged on your patience by going rather longer than we said we would. Thank you very much indeed to both of you. We have learnt a lot from your evidence. Thank you for taking the trouble to come.
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Moltex Energy LLP – Written evidence (REI0009) Authors: Ian R. Scott M.A. Ph.D. and John Durham The Simple Molten Salt Reactor Summary
1. This submission is in response to the question relating to the medium term “Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?” It describes an option that has real potential to eliminate energy imports to the UK, almost completely decarbonise electricity generation and reduce electricity prices to below current levels, allowing substantial adoption of electrical domestic heating as a replacement for fossil fuels.
2. In the submission we set out the current technical status of a concept for a
potentially transformative design of a nuclear reactor using a molten salt based fuel. The design is based on a scientific breakthrough by a British scientist from outside the nuclear field – a retired Chief Scientist from Unilever plc.
3. The design has over the past year been exposed to a wide range of experts within the nuclear field and is now widely considered interesting and worthy of deeper study. Those who have commented and share this view include
Tim Abram, Professor of Nuclear Fuel Technology, Manchester University who is actively supporting Moltex Energy in performing reactor neutronics calculations Fiona Rayment, Director of Fuel Cycle Solutions, National Nuclear Laboratory and her team with whom we are liaising in developing the concept Steve Cowley, CEO of the UK Atomic Energy Authority who described the concept as “interesting and promising” and has offered to have his engineers at the Culham Centre review the design Paul Madden FRS, Provost Queens College, Oxford Tim Stone, Expert Chair of Office for Nuclear Development and Senior Advisor to the Secretary of State, DECC from 2007-2013 who said it was the most exciting development in nuclear energy for decades David Whitmore, Nuclear Projects Director, Atkins Ltd and Paul Littler, Technical Director Atkins Nuclear. Moltex Energy is now working with Atkins on refining the design to meet UK safety requirements and producing an initial cost estimate for construction. Tony Roulstone, Cambridge Nuclear Energy Centre and former MD Rolls Royce Nuclear, who was sufficiently impressed to arrange a seminar to expose the whole Cambridge University Nuclear group to the concept. Geoff Parks, Senior Lecturer in Nuclear Engineering , Cambridge University
4. The key features of the reactor that make it potentially transformative are
a. An extraordinary level of intrinsic safety, due to three factors fundamental to the design,
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i. Virtual elimination of dangerous gaseous radioactive fission products such as cesium and iodine that can spread radioactivity over thousands of miles in the event of catastrophic damage
ii. Operation at atmospheric pressure, eliminating potentially explosive leaks
iii. Elimination of the need to “over fuel” that is essential in all conventional reactors but that can lead to a runaway nuclear reaction in the event of control failures
b. Simple, low cost and largely factory based construction and low operating costs that would allow it to produce electricity competitively with fossil fuels
c. The ability to use low purity reprocessed fuel that carries little more potential for weapons proliferation than does the original spent nuclear fuel. Such low purity fuel should be able to be produced economically, unlike Sellafield’s high purity MOX fuel. This would eliminate the need for a geologically stable waste storage facility.
5. While similar claims have been made for other molten salt reactor designs, this
reactor design is fundamentally simpler, safer and capable of rapid development. It requires no novel materials or manufacturing techniques, all structures are comfortably within the current state of the engineering capability existing today in the UK. Atkins Ltd is presently preparing a preliminary capital cost estimate for the reactor.
6. The breakthrough behind this reactor is entirely novel and is the subject of
worldwide patent applications, with the UK patent fast tracked and expected to be granted essentially as filed within the next few months, following a very favourable examination report. This intellectual property position unlocks the potential for one company or nation to develop a globally dominant position in civilian nuclear energy, since this reactor has the potential to render conventional reactor designs uncompetitive. It would be a massively disruptive technology to the existing nuclear industry, which is of course largely based overseas.
7. It is the intention of Moltex Energy to license its technology during 2015. Given the
absence of leading nuclear reactor vendors based in the UK, it is likely that only direct government backing will result in this intellectual property being retained in the UK.
8. While the House of Lords enquiry is restricted to the UK impact of technology, the
global impact of the Simple Molten Salt Reactor is of even greater importance. Current global plans for adoption of low carbon power generation, including nuclear and renewables, are projected to still result in a doubling of global electricity generation from fossil fuels by 2040. Only through a technological breakthrough like the Simple Molten Salt Reactor, capable of implementation on a global scale and on much shorter short time scales than generally considered “normal” for new nuclear designs does it seem possible that the world will not suffer potentially devastating harm through CO2 driven climate change.
Background
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9. The idea of using a molten salt of uranium or plutonium as the fuel in a nuclear reactor instead of solid fuel rods originated at the Oak Ridge National Laboratory in the late 1940’s. Two prototypes were actually built and operated successfully but today no such reactor exists or is planned for building in the next several decades.
10. This is a great pity. At the most fundamental level, molten salt fuelled reactors have
huge safety advantages over conventional reactors, eliminating, rather than controlling, major hazards. The most important of these are:
a. Molten salt fuels can be formulated that capture almost all volatile fission
products within the fuel salt in a non-volatile form. The danger of an accident producing an airborne plume of radioactive iodine, caesium, tellurium etc as occurred at Chernobyl and Fukushima is thus eliminated.
b. Molten salt reactors can operate with no excess reactivity that has to be damped down by control rods. Control failures (like Chernobyl and others) cannot therefore cause a runaway chain reaction that will destroy the reactor.
c. Molten salt reactors can operate at atmospheric pressure with neither water nor high pressure gas in the reactor core, which removes the major hazards of steam explosions or high pressure gas release.
11. It is significant that these three advantages would have prevented or hugely reduced
the severity of the three biggest civilian nuclear accidents (Chernobyl, Fukushima and Three Mile Island). The massive increase in capital costs of reactors since those disasters has been largely caused by the costs of increased safety systems and containment grafted onto the same old type of reactors, in order to assure the public and regulators that such accidents could never happen again. But the fundamental hazards have merely been controlled and contained – not eliminated.
12. The generic Molten Salt Reactor is in fact unique among all the “generation IV”
nuclear reactors in possessing all three of these fundamental advantages of eliminating rather than controlling hazards. Yet it is the least developed of all those Generation IV reactors and has the longest estimated time to commercialisation.
13. Why?
There are many conceptual designs for molten salt reactors, each of which has its own unique combination of advantages. But all the designs share a fundamental design principle which has been handed down from the original prototype reactors at Oak Ridge. The molten salt is pumped around a circuit between a reaction chamber - where the fuel achieves criticality and generates heat - and a heat exchanger where that heat is used to generate steam and hence electricity as shown here.
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14. So deeply embedded is this idea that it is sometimes quoted as the defining
advantage of molten salt reactors – that the fuel is also the primary coolant. But it is not an advantage - it is rather a problem that requires very complex and challenging engineering to solve.
15. These challenges include
a. Manufacturing pumps and valves capable of operating with high temperature, intensely radioactive and corrosive molten salt for long periods
b. Creating mechanisms and protocols to safely inspect and replace these pumps and valves when they have become highly radioactive from exposure to the fuel salt and its associated neutron flux
c. Finding novel materials capable of withstanding the intense neutron flux in the reaction chamber for the life of the reactor or creating mechanisms to allow the replacement of the intensely radioactive reaction chamber during the life of the reactor.
d. Manufacturing thin walled heat exchangers capable of resisting the corrosive molten salt and the associated neutron flux for decades
e. Designing and building helium bubbling and foam separation systems to remove volatile fission products and partially remove insoluble fission products from the molten fuel salt, which will otherwise block pumps and heat exchangers
f. Designing and building on line chemical reprocessing systems to remove the remaining insoluble fission products and to maintain the chemical state of the fuel within the tight bounds required to minimise its corrosive power
g. For many designs, establishing new processes to isotopically separate 6Li from 7Li sufficiently economically to allow use of many tons of pure 7Li per reactor
h. Draining fuel rapidly from the large reaction chamber in the event of pump failure before residual decay heat raises its temperature above the safety limit of the chamber’s materials
i. Ensuring that no failure mode results in molten salt freezing in places where it can do damage - such as pumps, valves, heat exchangers, drain systems, chemical processing plant etc.
16. None of these challenges are insuperable, but they are difficult and complex.
This is a particular problem in the regulatory environment within which nuclear operates, where reactor vendors must prove to a very high level of confidence that each and every one of their systems will operate as designed under all conceivable conditions.
17. All of the problems listed above are consequences of the basic design
principle of pumping the fuel salt around a reaction chamber/heat exchanger circuit. Is this really necessary?
18. The very first outline design for a molten salt reactor actually did not do this.
The Oak Ridge scientists’ first idea for a molten salt reactor in 1950 had the molten salt confined to static tubes around which a coolant circulated. The
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reactor actually looked rather like a conventional reactor but with molten salt fuel replacing the uranium oxide fuel pellets. But they concluded that the tubes containing the molten salt would have to be no more than 2mm in diameter because low thermal conductivity of the salt would result in the salt boiling at the centre of the tube if it was any wider. Such narrow tubes were completely impractical and so the Oak Ridge scientists abandoned this simple concept and instead designed pumped systems that created turbulent mixing of the fuel salt and therefore prevented the boiling problem.
19. That early decision was something of a tragedy that sent molten salt reactor
designers down an ultimately very difficult path. And the decision was wrong. The calculation that tubes had to be less than 2mm in diameter neglected the contribution to heat transfer that resulted from convective flow of the salt - as illustrated to the right. The Oak Ridge scientists cannot be blamed for this – they knew they were neglecting convection - but in 1950 the mathematical and computational tools to calculate the effect of convection on heat transfer were still 30 years away from being invented! They had no choice but to ignore convection (it might also have been significant that they were designing a reactor for an aeroplane and relying on gravity driven convection for heat transfer would have been perhaps unwise!)
20. Today however, the tools of computational fluid dynamics are in routine use and
their application to the problem of molten salt reactor design opens up a new and far simpler design for molten salt reactors.
Heat transfer within fuel tubes – data & patents 21. The ability of molten fuel salt to transfer heat effectively to the tube wall through
convection is the vital breakthrough in this reactor concept. It was therefore essential to rigorously quantitate this effect, which will ultimately determine the power density that can be achieved in the reactor core. This was carried out independently by two groups, an engineering consultancy, Wilde Analysis Ltd, specialising in computational fluid dynamics and an academic group led by Dr. Andrea Ciancolini, lecturer in thermal hydraulics at the University of Manchester. Both groups used data for the physical properties of the fuel salt taken from the scientific literature.
22. The graph to the left shows
how the peak temperature of the fuel salt varies with the diameter of the fuel tube when the average power density is 115kW/litre, which is approximately the power density in a modern PWR nuclear reactor. Tubes as wide as 30mm can clearly be used without the salt reaching boiling point.
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23. If tubes as narrow as 20mm diameter are used then power densities substantially
higher than those in PWR reactors can be safely achieved.
24. For contrast, the red line shows the calculated temperature ignoring convection, confirming the Oak Ridge scientists view from 1950 that only very narrow tubes could be used if convection could not be relied on.
25. This discovery is the basis for international patents filed in February 2014. The UK
patent application has been fast tracked by the UK Patent Office through its “Green patent fast track process”. The examination report indicates that no substantive issues of patentability have been found and the patent is expected to be granted substantially as filed in early autumn of this year.
26. There is thus the opportunity for worldwide exclusive sale of these reactors giving
the nation that develops them a globally dominant position in civilian nuclear energy. This is a disruptive innovation that can fundamentally reshape the global nuclear industry, displacing the currently dominant (and foreign owned) national and industrial players
The many new possibilities for Molten Salt Reactors
27. The discovery that molten salt fuel can be used in nuclear reactors without the need to pump it around a circuit opens up a very large range of new reactor designs – most designs using solid fuel rods could be adapted to use molten salt fuel. The remainder of this paper describes one particular concept which was selected for more detailed development because of its inherent simplicity of construction and intrinsic safety. These two factors would be expected to result in much lower capital cost of construction, which is the key to enabling massive worldwide expansion of nuclear energy.
28. The reactor, the Simple Molten Salt Reactor, is designed to operate using the huge
stockpiles of spent conventional nuclear fuel, though use of enriched natural uranium is also feasible. The reactor design is compatible with using fuel created via a very simple and low cost reprocessing procedure that would be both far cheaper than conventional reprocessing and would avoid increasing the proliferation risks associated with such spent fuel.
29. Successful deployment of the reactor would consume those stockpiles of spent fuel
within a few decades. There would then be an economic case for developing a nuclear breeder version of the reactor (this exists now in outline), which would operate on the thorium fuel cycle. That outline design is far simpler, safer and cheaper than current designs for sodium cooled fast breeder reactors.
30. But the time when breeder reactors will make economic sense is not today and the
potential for nuclear breeding is only mentioned to reassure the reader that this is genuinely a long term solution to the worlds energy needs.
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Design of the simple MSR 31. The conceptual design of the reactor is shown below. It is based on a cylindrical tank
filled with a molten coolant salt (shown in yellow). All components are inserted into the tank from above with no penetrations of the tank walls. There are only three main components in the reactor.
a. Assemblies of fuel tubes arranged in an array at the centre of the tank b. Neutron reflector structures that also act as mountings for the impeller and as
baffles to force the circulating coolant salt to pass through the fuel tube and boiler tube arrays
c. Boiler tube arrays that take heat from the coolant salt and generate steam which is passed to turbines to generate electricity.
32. All of these components are factory manufactured in segments that are simply lowered into the reactor tank and secured. They can all be easily removed and replaced as needed during the life of the reactor making maintenance far simpler than for other reactor designs. There are no non replaceable components that experience significant radiation damage during reactor operation.
33. The reactor tank is manufactured from nickel superalloys which have been proved to
be resistant to the molten coolant salt for long periods. It sits in a second, steel tank which in turn sits in a concrete lined pit below ground level. There are thus three levels of containment for the molten salt, in addition to the fuel tubes themselves.
34. Above the reactor tank is a gas tight (but not pressurised) containment vessel which
maintains an inert argon atmosphere above the reactor tank, thereby avoiding contamination of the molten salts with oxygen or moisture. Mechanisms to insert and remove reactor components are located within this vessel. This acts as the containment barrier for the small amount of gaseous fission products which are not
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trapped in the molten fuel salt (see below). It is likely that this single containment barrier will be sufficient as the magnitude of the gaseous radioactive “source term” is so very low in this reactor.
Engineering practicality 35. Most molten salt reactor designs result in significant challenges in materials science
that must be overcome before they can be built, not least among which are constructing complex pumps and valves that must survive intense neutron radiation and hot corrosive molten salt for decades.
36. The Simple MSR however avoids most of these challenges. The boiler tubes, reactor
tank and neutron reflector structures are all exposed only to the coolant salt which is a mixture of zirconium, sodium and potassium fluorides operating at temperatures between 450°C and 600°C. Nickel alloys, which are routinely used today in coal fired power stations, have been proved resistant to substantially more challenging conditions. Of these structures, only the neutron reflector is exposed to significant neutron flux thereby avoiding neutron damage to any structure required to provide physical strength (neutron irradiation damages metal structures).
37. The major materials challenge is the fuel tube. This is exposed to a chemically
complex and much hotter molten salt mixture, containing not only the nuclear fuel (uranium, plutonium and sodium chlorides) but also the full range of fission products. It is also exposed to intense neutron irradiation.
38. Manufacturing components to survive these conditions
for long enough to be permanent reactor structures would be extremely challenging. However in the Simple MSR these are not permanent structures. They are consumable items that are removed from the reactor when the fuel is depleted and replaced with fresh assemblies. The maximum operating life will be no more than 5 years and can easily be made shorter without sacrificing the cost effectiveness of the reactor.
39. The diagram illustrates how the fuel tubes will be
mounted in assemblies. The structural strength of the assembly is provided by nickel alloy structures which are exposed only to the coolant. The fuel tubes are manufactured from molybdenum which is a refractory metal which can be used at temperatures up to 2000°C, far above the boiling point of the fuel salt, and which is known to be extremely chemically resistant to molten salts. The tubes are secured by a single weld at the bottom to a lower support grid and are supported laterally at the top with a top tube support grid which allows them to expand and contract freely. The fuel
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tubes are open at the top to allow fission product gasses to escape so as not to build up pressure.
40. This arrangement ensures that the fuel tubes experience minimal physical stress. It is
anticipated that this will allow industry standard molybdenum tubes to be used. Experimental validation that they maintain sufficient strength and corrosion resistance will however be required by regulators but a successful outcome of that testing is very likely given the very low level of physical strength that will be required.
41. One aspect of the fuel tube design which perhaps requires explanation is the spiral
shape of the narrow upper part of the tube. This spiral structure is used so that there is no straight line path for neutrons generated in the core to pass out of the reactor. Straight tubes would result in narrow but quite intense neutron beams shining onto the roof of the reactor building, an undesirable factor. The coolant salt is an effective neutron absorber with a 1 meter layer providing a 10,000 fold reduction in neutron flux.
Fate of the fission products
42. Fission products are by far the most dangerous factor in nuclear reactors. While all reactors produce similar types and amounts of fission products, their disposition and fate is very different, and fundamentally safer, in the Simple MSR than in other reactors.
43. In conventional reactors many fission products are produced as gasses – the noble
gasses xenon and krypton which have low biological hazard but also cesium and iodine which are far more dangerous. These gasses are partially trapped at very high pressures in pores in the solid fuel or escape from the fuel pellets into the cladding tubes where they build up to moderate pressures. In the event of a core failure, these gasses can be (indeed have been) released creating a highly radioactive airborne plume that can travel thousands of miles from the reactor site.
44. In the Simple MSR, the noble gasses pass out from the fuel tubes as they are
produced. Most other fission products form non volatile salts which mix safely with the fuel salt. The sole exception is zirconium which forms a volatile chloride which will pass out with the noble gasses. The zirconium chloride rapidly dissolves in the large volume of coolant salt with which the gas phase is in contact, which already contains large amounts of zirconium salts. The noble gasses have low biological hazard but can nonetheless by simply removed from the argon gas filling the reactor vessel by passing it through cryogenic filters where they condense to solids which can be removed and stored until safe (several months would suffice).
45. The remaining class of fission products are the noble metals such as molybdenum,
platinum etc. These are insoluble in the molten salt and will deposit safely on the inner wall of the fuel tube – effectively negative corrosion.
46. Two further chemical challenges arise from the use of uranium and plutonium
trichlorides as fuel. The first is that fission results in a small net release of chlorine.
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This would convert some of the uranium trichloride to the tetrachloride which has significant volatility. However, application of a thin sacrificial coating of chromium metal to the inside of the fuel tube will scavenge any chlorine released thereby maintaining a very low concentration of volatile uranium tetrachloride and keeping the fuel salt strongly reducing and therefore much less corrosive.
47. The second is that chlorine atoms undergo a small degree of transmutation to
sulphur in the reactor. Sulphur reacts strongly with molybdenum and could cause corrosion of the tube wall. However, fission produces substantially more molybdenum than sulphur so any sulphur generated will be instantly neutralised by the molybdenum produced by fission.
48. The net effect of all this chemistry is that even catastrophic destruction of a Simple
MSR, for example by a large bomb, would not lead to the release of large amounts of airborne radioactivity.
49. These conclusions about the volatility of fission products are based on well
established thermodynamic principles as embodied in a commercial computer program Outotek Chemistry HSC7 (recommended to Moltex Energy by Professor Derek Fray, FRS) but would nonetheless need to be experimentally verified as part of the regulatory approval process.
Fuel preparation and recycling
50. Neutronic calculations carried out by Professor Abram’s group at Manchester University have shown that the reactor will require a fuel containing approximately 20% reactor grade plutonium (containing 12% fissile 239Pu) to achieve criticality. The reactor has however two major advantages over other reactors in the type of fuel it can use.
51. Solid fuel reactors using reprocessed plutonium require it to be in a very pure state in
order that the physical properties of the solid fuel can be assured. Such highly purified plutonium is both very expensive to produce and carries a high proliferation risk since it is also pure enough for weapons use.
52. The molten fuel for the Simple MSR does not need to be pure at all. It can contain
mixtures of uranium, plutonium and higher actinides like curium and americium. It can also contain substantial amounts of fission products, particularly the lanthanides. These must be completely removed for fuel to be used in conventional thermal neutron reactors since they are strong neutron poisons. Because the Simple MSR is a fast neutron reactor it is largely immune to such poisons.
53. As a result of this tolerance of low purity, a far simpler and cheaper reprocessing
process than that used today should be possible. Professor Mount at Edinburgh University, head of the REFINE consortium which is researching options for a closed loop nuclear energy cycle, is currently analysing possible options for fuel production on behalf of Moltex Energy.
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54. It seems likely that this will allow an economically viable reprocessing of current spent nuclear fuel stocks, leaving a waste residue only requiring secure storage for a few hundred years instead of the 10’s of thousands of years for the original spent fuel. The need for a geologically stable repository for such waste will thus be eliminated.
55. The use of such impure fuel means that the technical challenge for an organisation
diverting the fuel to illicit weapons use would be little different to their starting with the original spent fuel. The first 80% of purification is easy, it is the final 20% where the challenge lies. Closing the nuclear fuel cycle in this way thus avoids the major increase in proliferation concerns that are associated with conventional reprocessing methods.
Passive and intrinsic safety of the simple MSR
56. While the safety of the reactor has already been discussed in part, it is helpful to summarise the many ways in which it is safer than other reactors.
57. No accumulation of dangerous volatile fission products
58. No high pressures in the reactor core that could cause steam or gas explosions
59. The reactor can be continuously refuelled while operational so that it is not necessary to have excess fuel in the core which is “damped down” by control rods until needed. This eliminates the possibility of design failure, accident or operator error rendering the reactor super critical with resulting massive damage to the reactor core
60. Both fuel and coolant salts are chemically stable, reacting with neither air nor water
61. Fuel and coolant salt are chemically compatible and miscible so in the unlikely event of damage to a fuel tube, the fuel mixes with the large volume of coolant rendering it non critical.
62. The reactor has a very strong negative temperature coefficient of reactivity – this means that if the fuel heats just a little above its design temperature the nuclear chain reaction shuts down. Since the reactor can tolerate quite large temperature increases above its design level this negative temperature coefficient makes it passively very safe. If all systems fail and heat is no longer removed, the reactor heats up and the nuclear reactions cease. It is therefore arguably not necessary to have emergency shut down control rods in the reactor.
63. The use of a “pool” of coolant held within multiple tank walls and below ground level makes a loss of coolant accident virtually impossible. Even so, the reactor has a very strong negative void coefficient for the coolant so any loss or displacement of coolant from around the fuel tubes would instantly shut down the nuclear chain reaction.
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64. Loss of systems to remove heat from the coolant (a so called Loss of Heat Sink Accident) would eventually result in the coolant overheating. The large volume of coolant means it can safely absorb residual heat from the fuel tube array for some hours. After that, additional cooling is required which would be made passively safe using similar mechanisms as in conventional reactors (gravity fed water supplies to the boiler tubes for example). However, in extremis if all systems and their backups had failed, the coolant salt would boil several hundreds of degrees below the boiling point of the fuel salt ensuring that the fuel tubes did not overheat enough to release volatile radioactivity. The vapour from the boiling coolant salt would condense on the inside of the gas containment structure and return to the tank. The reactor would then remain safe indefinitely. A similar though less effective “last ditch” mechanism using boiling water rather than boiling coolant salt has been approved for the Westinghouse AP1000 reactor.
12 September 2014
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National Grid – Written evidence (REI0017) Executive Summary National Grid’s job is to connect people to the energy they use, safely. In providing this vital service we are acutely aware of the importance of delivering reliability and value for money for consumers. A focus on driving down costs whilst continuing to deliver greater service reliability sits at the heart of our business model. National Grid owns and operates the high voltage electricity transmission system in England and Wales, which at 99.99995% is the most reliable network in Europe. Through a well planned development and maintenance programme, our network continues to be extremely resilient to peaks in consumer demand and sudden shocks. Over the next decade, we are investing around £20 billion to ensure that our electricity and gas networks continue to provide safe and reliable energy supplies to customers, as well as future-proofing against significant security and weather events. Working closely with DECC and UK security agencies we have identified various assets that are deemed to be Critical National Infrastructure (CNI)- where any supply loss could have a substantial material effect on the public, commerce and industry- and ensured there are sufficient measures in place to enhance the resilience of these assets. In addition, as the National Electricity Transmission System Operator (NETSO), we operate the whole electricity transmission system in Great Britain and are responsible for co-ordinating and directing power flows across the high voltage network. In the event of a sudden shock, such as an instantaneous loss of generation, we have thoroughly tested plans and procedures in place to ensure the network balancing frequency does not fall outside of the statutory limits stipulated in our licence and industry operating codes. To effectively manage unforeseen demand increases or generation unavailability, National Grid needs access to rapid sources of extra capacity in the form of either generation or demand reduction. In response to Ofgem’s 2013 Capacity Assessment Report, which highlighted a narrowing of capacity mid-decade, National Grid has developed two additional system balancing tools (Demand Side Balancing Reserve and Supplementary Balancing Reserve). These balancing tools will only be used as a last resort in the unlikely event of a shortfall of generating capacity in the electricity market and allow us to procure additional capacity over the winters of 2014/15 and 2015/16. To address longer term capacity needs, the government has introduced Electricity Market Reform to encourage low-carbon generation and ensure the continued security of supply. Developing an energy system to support our economic prosperity in the 21st century is one of the greatest challenges that National Grid faces. Shifts in the way energy is used, the need to manage ageing infrastructure and a changing energy supply mix all drive a need for urgent investment. In particular, investment in networks to connect new sources of power and gas is a priority for ensuring security of supply as the country moves towards a low carbon economy. Part of that challenge is ensuring that new power sources, whether from nuclear,
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wind and other renewables are connected to the electricity transmission network in order to carry the electricity to where it is needed. In England and Wales, much of the new electricity generation will be in the coastal areas, or offshore, where there is currently very little existing transmission infrastructure. A stable investment framework is essential for minimising the costs of financing these investments. Energy efficiency should be a core part of long term infrastructure planning, as domestic and wider energy efficient measures require effective planning. An active demand side will play an important role in meeting the challenge of delivering energy affordably and sustainably, and will reduce the need for investment in generation and networks. In order to successfully encourage greater demand side participation there needs to be a clear, stably policy framework that is supported by delivery mechanisms that enable smart technology and initiatives to drive greater consumer awareness and participation.
1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base?
1.1 As the NETSO, we co-ordinate and direct power flows across the transmission system in accordance with strict security standards - balancing the system in the final hour before real-time to maintain system frequency. This role is called residual balancing and occurs after the market has closed (known as gate closure). It accounts for less than 3% of energy transactions in the market. National Grid does not generate power - neither do we sell it to consumers. Customers pay their bills to energy suppliers, who buy enough electricity to meet their customers’ needs from electricity producers. Once that electricity enters our network, our job is to ‘fine tune’ the system to make sure supply and demand match second by second. For the last hour leading up to real-time, we operate the system in real time, balancing supply and demand to deliver electricity securely to customers via the transmission network. We do this through a market tool called the balancing mechanism. 1.2 Historically, the UK’s electricity transmission system has been very resilient to peaks in consumer demand and sudden shocks. National Grid’s electricity transmission network in England and Wales has a reliability standard of 99.99995%, which is the most reliable network in Europe117. The high voltage electricity transmission network forms part of the UK’s Critical National Infrastructure and as such National Grid must ensure that our facilities and processes are resilient. 1.3 Using a variety of data including historical demand statistics, weather forecasts and knowledge of any significant media events, such as national football games, National Grid’s Energy Forecasting Team can closely predict the overall national electricity demand for a given day. An Operating Plan is produced a day ahead which brings together forecast generation and demand with the network information, and identifies any potential issues. In addition, the team must also ensure that there is sufficient STOR and response available to manage any unexpected events.
117 National Electricity Transmission System Performance Report 2012- 2013, National Grid http://www2.nationalgrid.com/UK/Industry-information/Electricity-transmission-operational-data/Report-explorer/Performance-Reports/
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1.4 Demand side products are an important tool in balancing supply and demand, enabling the deferral of network investment on the part of network owners, meeting power requirements of suppliers in the wholesale market and/or balancing national demand in real time. We regularly contract with a number of demand service providers to deliver balancing services as part of our SO responsibilities. This includes contracts to reduce demand at short notice under our Short Term Operating Reserve (STOR) or those aimed at solving specific events on the transmission system such as frequency response services. Our transmission licence obliges us to do this in a manner which represents the best value for money for consumers. 1.5 In the event of a sudden shock, such as a generator unexpectedly tripping off the system, National Grid has to cater for the instantaneous loss of 1200MW of generation, without the frequency going outside of statutory limits stipulated in our licence and industry operating codes. To manage this, National Grid needs access to rapid sources of extra power in the form of either generation or demand reduction, to be able to deal with unforeseen demand increase or generation unavailability. We do this by holding reserve and response; mainly power stations which are willing to increase their output in response to a frequency drop due to loss of generation on the system. Generators can sign up to a contract to be paid to provide these services. As we go forward and as in-feed losses increase, for example as larger nuclear units are built, then greater levels of reserve and response will be needed. 1.6 If the operating plan identifies any potential shortfall in generation, or an unexpected spike in consumer demand, we can notify the market players using a number of mechanisms, such as; Notice of Insufficient System Margin (NISM): a formal communication that lets market
players know that our margin is not as large as we would like it to be at a particular time of that day.
High Risk of Demand Reduction (HRDR): we use this when we don’t have much time to notify the market of a sudden shortfall.
Demand Control Imminent (DCI): if the market does not respond to the HRDR, we can issue a DCI notice asking the electricity distribution companies to reduce demand across their networks.
1.7 The evidence base relies on system modelling and analysis by National Grid and other parties to best predict how new technologies and customer behaviour will impact the system. Along with National Grid’s investment and commitment to maintaining our electricity infrastructure assets, the reliability of the system is a testament to the forecasting work to balance supply and demand.
2. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’?
2.1 It is National Grid's job to ensure that we continue to provide safe, reliable and cost efficient energy across our electricity transmission system, which not only meets the needs of our customers now but also in the future. To ensure that we maintain these standards and that there is sufficient transmission infrastructure to support future energy demand we
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are investing around £20 billion in extending and strengthening our networks over the course of our 8 year RIIO price control. 2.2 We ensure that our networks continue to be safe and reliable through our on-going commitment to the highest standards of network development and maintenance. Over time the transmission network requires maintenance, upgrades and new connections to ensure its reliability and flexibility. Over the next decade we will be spending around £90 million a year and 774,483 man-hours maintaining the UK’s transmission network to ensure that it remains resilient and reliable. 2.3 Developing energy infrastructure that can underpin our economic prosperity in the 21st century and connecting new technologies up to the Grid is one of the greatest challenges that National Grid faces. Part of that challenge is ensuring that new power sources, whether from nuclear, wind and other renewables are connected to the electricity transmission network in order to carry the electricity to where it is needed. In England and Wales, much of the new electricity generation will be sited on the coast, or offshore, where there is currently very little existing transmission infrastructure. New electricity transmission lines will therefore be required in these areas. We will also need to carry out work on existing areas of the network to upgrade and reinforce it to make it fit for these new low carbon sources of electricity. 2.4 National Grid is also investing in future-proofing our assets by working to protect all our sites to the standard of a 1 in a 1000 year flood event. We have invested £20 million in flood defence since 2008 and we estimate a total spend by the end of 2018 will be £70 million. 2.5 We continue to improve our network resilience capacity across all of our UK operations by rigorously testing our recovery plans with electricity generators, other industry partners, and government. We continue to work closely with DECC and the security agencies to identify assets within our gas and electricity network that are deemed to be Critical National Infrastructure- where any supply loss could have a substantial material effect on the public, commerce and industry- and ensure there are sufficient measures in place to enhance the resilience of these assets. A close working relationship with government agencies and other UK energy network owners has allowed us to provide enhanced security of supply for the nation using the latest technologies whilst delivering value for money for consumers. 2.6 In addition to maintaining the resilience of our network, National Grid is working with DECC and Ofgem to secure additional capacity for the energy system. In response to Ofgem’s 2013 Capacity Assessment Report which highlighted a narrowing of capacity margins in the mid-decade period, National Grid has developed two additional system balancing tools (Demand Side Balancing Reserve and Supplementary Balancing Reserve) that could be used as a last resort in the unlikely event of a shortfall of generating capacity in the electricity market. These balancing tools will procure additional capacity support over the winters of 2014/15 and 2015/16. 2.7 National Grid has identified a need for up to 330MW of additional reserves for this winter and up to 1,800MW for the winter of 2015/16. These values are kept under review as the projected availability of power generation is a constantly changing landscape. We have
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also identified a requirement for 2016/17 and 2017/18. These volumes are based on ensuring sufficient capacity is available to meet the reliability standard set by government in terms of generation availability, continental imports and demand. Demand Side Balancing Reserve (DSBR): provides an opportunity for large consumers or
owners of small embedded generation to earn money through a combination of upfront payments and utilisation payments by contracting to reduce demand or provide generation when required. Further payments are received in the event that the service is utilised. The service would be required for short periods between 4pm and 8pm on weekday evenings between November and February.
Supplementary Balancing Reserve (SBR): a contract between National Grid and
generators to make their power stations available in winter, where they would have otherwise been closed or mothballed.
2.8 Based on our experience of running the system and on current information about plant availability and demand, with these additional balancing measures we expect the upcoming winters to be manageable. To address the longer term capacity needs, the government has introduced Electricity Market Reform to complement existing arrangements, encourage low-carbon generation and ensure security of supply. 2.9 National Grid is involved in administering EMR and is closely involved with the Contracts for Difference and the Capacity Mechanism. Our role is to assess how much capacity is required to meet the reliability standard set by government. The Government will then use this information to determine how much capacity to procure, and instruct us to run the Capacity Mechanism auctions and administer the successful capacity agreements as they come into force. The first Capacity Mechanism auctions will run in winter 2014, to provide capacity for 2018/2019.
3. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made?
3.1 Ofgem’s recent development of the network regulatory regime has culminated in the new RIIO regime (Revenue = Incentives + Innovation + Outputs). This framework builds on 20 years’ experience of effective incentive regulation and is now being emulated by others. The regime demonstrates best practice in balancing stakeholder priorities, including delivering required outputs at the most affordable prices. Network companies are strongly incentivised to drive efficiencies throughout the business to deliver lower costs for consumers. 3.2 The RIIO price control regime ensures significant levels of scrutiny and transparency are applied to our investment plans and the charges that we pass on to consumers. Stakeholders are engaged throughout the process and network businesses are required to develop business plans which demonstrably reflect our customers, consumers and other stakeholders’ requirements.
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3.3 Our investment in the electricity network is strongly influenced by our customers and stakeholders. As part of the RIIO price control process we engaged extensively with our customers and stakeholders on our business plan to 2021, to understand their priorities and requirements for our network against the cost of delivering different levels of service and investment. Our customers and stakeholders made it very clear that they want National Grid to prioritise safety, resilience, innovation and customer service and our investment decisions in our infrastructure will reflect this. 3.4 In response to our RIIO business plan, network outputs such as reliability, customer connections and new capacity were set for us together with incentives to deliver these outputs in the most efficient way for customers. So our revenue is ultimately dependent on our performance. We provide a comprehensive annual report to Ofgem which allows our performance to be checked against the agreed outputs. In addition, we continue to ask our stakeholders what they want us to deliver. 3.5 In planning and operating the UK’s electricity transmission system, including decisions on investment, National Grid and other transmission licensees in Great Britain apply the National Electricity Transmission System Security and Quality of Supply Standard (NETS SQSS). This standard has been developed with our customers. Any changes to the NETS SQSS are consulted on widely and ultimately reviewed and agreed by Ofgem to help ensure that they are in the interest of consumers. 3.6 A key objective of the NETS SQSS is to ensure that the electricity transmission system is reliable and that an appropriate level of security and quality of supply is available for electricity transmission. Other objectives include the facilitation of an efficient, co-ordinated and economical system of electricity transmission, the facilitation of effective competition in generation and supply and compliance with our legal obligations. 3.7 In practice, we use the NETS SQSS to determine the minimum requirements for connecting generation and demand and the optimum levels of transmission capacity between different parts of the network to facilitate an efficient energy market whilst maintaining a high level of system security. The NETS SQSS includes criteria to determine transmission capacity and ensures that an efficient level of redundancy is built into the network. As well as considering the requirements of the transmission system to meet different generation and demand conditions, the NETS SQSS ensures that there would not be a wide scale loss of demand in the event of unplanned or unexpected problems, for example the loss of a transmission line or part of an electricity substation due to third party interference or during a storm. 3.8 In making decisions about investment in our transmission system, where there are different options to connect customers or to provide additional transmission capacity, the costs and benefits associated with different options are compared. These costs and benefits include the capital costs of the investment, any impacts on transmission operating costs such as transmission losses or constraints and any impacts on the energy not supplied to consumers.
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3.9 In an industry where technology is evolving so quickly, one of our challenges is to achieve the correct balance and timing of investment. Investing too early could lead to costly under-used capacity. Delaying investment risks not having enough capacity where there are inefficient constraints on the system and we limit access to the network. The costs of either investing too early or late ultimately end up in consumer’s bills so an important part of our role is to work with our industry partners to minimise these costs to consumers. To make our investment plans more rigorous and transparent we have developed a Network Development Policy with Ofgem which sets out the network capacity required and the possible options for network development.
4. What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
4.1 Legislation at both UK and EU level forms the policy landscape which has a significant impact on the future energy system. The passing of the Energy Act 2013 is a significant step towards providing greater clarity on the future UK electricity market, both through the introduction of Contracts for Difference to support low carbon generation and a Capacity Market to ensure security of supply. The successful implementation of Electricity Market Reform is a key step towards securing adequate capacity from 2018-19 and to ensuring that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation. 4.2 Each year, National Grid publishes a document called UK Future Energy Scenarios (FES)118. This sets out our analysis of credible future energy scenarios to 2035 and 2050. National Grid has generated four scenarios in our 2014 FES for what the UK’s future energy landscape might look like based on the dynamics of affordability and sustainability. They are Gone Green, Slow Progression, No Progression and Low Carbon Life. All of the scenarios assume that the government defined security of supply standards will be met. 4.3 Guided by FES we believe that a number of steps need to be taken to ensure that the UK is on a trajectory to decarbonisation by 2020 and meets the targets set out by Government: Life extensions for existing nuclear power stations need to be confirmed and new plant
needs to obtain relevant consent and final investment decision approval. Sufficient consents, support and finance for offshore and onshore wind in order to meet
the target level in 2020 and beyond, as well as an effective supply chain in place to reduce barriers to delivery in the offshore industry.
Commercial deployment of technologies such as CCS and marine energy. Development of networks to allow increasing levels of variable and low carbon
generation to connect. 4.4 As the UK transitions to a low carbon economy, electricity supply and demand variability will increase. This will be driven by changes in the electricity generation mix; an increased in the proportion of variable renewable generation such as wind, solar and tidal, and a decrease in the proportion of flexible, conventional generation likely to be fuelled by gas.
118 Future Energy Scenarios 2014, National Grid http://www2.nationalgrid.com/uk/industry-information/future-of-energy/future-energy-scenarios/.
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Other changes such as access to new system balancing tools, a large increase in demand side response and changes to the time of electricity use, storage and interconnection are likely to increase as the proportion of flexible generation declines. The new balancing services (NBS) are a precursor to the Capacity Market; and amongst the items they look to facilitate is allowance for greater DSR participation whether through the NBS or aggregators participating in the Capacity Market. 4.5 At National Grid we are assessing the impact of these changes and the resulting challenges and opportunities both for energy consumers and for future grid operation. Through our RIIO price controls, we are focused on identifying robust, cost effective solutions to these challenges to ensure we can support delivery of a secure, low-carbon future as economically and efficiently as possible. Our focus is on enabling an orderly, economic transition to 2020 that maintains security of supply, facilitates the achievement of climate change targets and provides a good foundation for further change required in the period to 2050 and beyond. 4.6 From our perspective as electricity System Operator the challenges include implications for reserve, system frequency managements and inertia as well as the impact on the physical transmission network on power flows, voltage management and fault levels. The transition must be done in a way that minimises consumer bills, and so the increased supply and demand variability will need to be matched with an equivalent level of supply and demand flexibility and responsiveness. National Grid has recently published its System Operability Framework report which provides further analysis on these challenges and starts to lay out some approaches to addressing them119. 4.7 In the medium term it is important that industry works together to develop ways to effectively incentivise and enable demand side response including where consumers ‘time shift’ non time-critical demand to when generation and/or network capacity is available. 4.8 An active demand side will play an important role in meeting the challenge of delivering energy affordably and sustainably, and will reduce the need for investment in generation and networks. As System Operator and EMR delivery body we are enabling greater demand side participation in the energy market. Although the direct impact we can have is limited, suppliers through their relationships with consumers have the opportunity to drive more substantial participation. There have been recent positive developments in demand side but we recognise that more needs to be done. In order to successfully encourage greater demand side participation there needs to be a clear, stable policy framework that is supported by delivery mechanisms that enable smart technology and initiatives to drive greater consumer awareness and participation.
5. Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure?
5.1 There are a number of developments expected in the years to 2020 which should help us understand the future investment landscape better. Over the next few years we are likely to
119 System Operability Framework 2014 Report, National Grid http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/System-Operability-Framework/.
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get an insight into future developments into Carbon Capture and Storage (CCS) as demonstration projects progress. The picture should also become clearer on the number of new nuclear plants that may be built as decisions on their development are made. Shale Gas test wells should give us greater insight to the role shale gas might play in our future gas supply. These new technologies, assessed alongside existing technologies, data from our stakeholders, political and economic changes in the UK and Europe, as well as market developments such as the Capacity Market, allow us to create a this holistic, plausible set of future scenarios on which to base our investment decisions. 5.2 We use these scenarios internally as a reference point for a range of our modelling activities including network analysis that enables National Grid to identity potential electricity network investment requirements in the future. In addition the scenarios feed into a range of other outputs including those for security of supply, Europe and shorter-term supply demand analyses. National Grid uses the FES to develop our Electricity Ten Year Statement, Network Development Policy and System Operability Framework to inform future decisions on investment in our electricity infrastructure. 5.3 The Electricity Ten Year Statement120 is produced by National Grid in our role as National Electricity Transmission System Operator and aims to provide clarity and transparency on the potential development of the Great Britain transmission system for a range of scenarios. The document considers this development through strategic network modelling and design capability, while trying to capture future uncertainty with regards to the generation mix, operation of the network and technology development. In last year’s publication, we outlined our proposed Network Development Policy (NDP). This defines how we will assess the need to progress wider transmission system reinforcements to meet the requirements of our customers economically and efficiently, taking in to account the risk to consumers.
6. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
6.1 The decarbonisation of electricity production will increase the challenge of operating the electricity transmission system in a number of ways. In our recent FES publication, our “Gone Green” scenario shows 26GW of wind and 7.5GW of solar in 2020, rising to 51GW and 15.6GW respectively in 2030. As the volume of renewable generation continues to grow three challenges will emerge. 6.2 The first challenge is that many of the new energy sources are remote, such as offshore wind, onshore wind in sparsely populated areas and coastal nuclear stations, so additional transmission capacity will be required to transport the energy to the main centres of population. The current works to provide additional capacity between Scotland and England are a good example of this. The visual impact of this work is being minimised by the use of a sub-sea cable and SMART technology to make the best use of existing assets.
120 Electricity Ten Year Statement 2013, National Grid http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Electricity-ten-year-statement/.
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6.3 The second challenge relates to the uncertain and variable output from wind and solar generation. To ensure a reliable supply of electricity, reserves must be held to cover for this uncertainty. In the past these reserves have been provided by part loaded generation that can be increased if needed. This approach has its limitations as power plant can typically operate between 50 and 100% output. Hence, for every megawatt of reserve, it is necessary to have a megawatt of generation operating. It can be seen that. This could limit the potential penetration of wind and solar. National Grid is currently investigating the following ways of mitigating this issue: Improved forecasting of weather and hence output Greater flexibility from conventional generation Varying the flows over the interconnectors to our European neighbours to allow reserve
to be shared Energy Storage Demand response – some demand such as water heating can be interrupted for short
periods without affecting the end customer. 6.4 The third challenge is that even if there is sufficient reserve, the total renewable output plus the ‘must run’ generation such as nuclear cannot exceed the demand on the system. This is most likely to occur overnight when demands are low. Potential mitigating actions include: Exporting the surplus energy via the interconnectors Energy Storage Incremental demand – for example charging electric vehicles overnight. 6.5 A further challenge going forwards is around operating the system during periods of low demand when it may become more difficult to source response services. As an example, existing nuclear plant is relatively inflexible, however we can manage this at present as we are able to obtain frequency response services from other generation such as gas and coal fired synchronous plant. However, this may not be the case going forward, particularly when demand is low and only nuclear and renewables are running. As such, we would like to encourage all new generation, including new nuclear plant, to be flexible around the way in which it operates and to be capable of providing response services. 6.6 The closure of coal fired power stations presents another challenge. This is not simply a matter of replacing them with another technology, but also represents loss of fuel diversity and energy storage. As the demand for electricity reduces significantly overnight, many power stations can reduce load or shut down. The ability to take this reduction on either coal or gas fired plant gives flexibility between the national demand for coal and gas. Hence it has been possible to reduce demand for gas by burning extra coal which was already stored at the power stations. The closure of coal plant will remove both a major energy store from the power system and a means of responding to a shortage of gas. 6.7 Finally, towards the end of the 2020’s it is likely that the use of electric heat pumps and vehicles will become more common. However, as shown in our UK FES, we anticipate the resultant increase in demand being an issue for the 2030s rather than the 2020s.
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6.8 The transmission system is changing to cater for the impact of the new generation that is being connected. National Grid considers system operability issues to the 2030s. In the short to medium term, the new Electricity Balancing System being commissioned in 2015 will provide a significant enhancement in National Grid’s capability to manage variable generation. Our forecasting models continue to be developed to account for embedded generation and we are working with Distribution Network Operators to obtain more real-time data on embedded generation.
7. What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models?
7.1 National Grid’s modelling tells us that achieving a resilient, affordable and low carbon electricity infrastructure by 2030 is challenging but achievable. This year, our range of FES scenarios is based on the energy tri-lemma of security of supply, affordability and sustainability. The Government has set a standard for electricity security of supply and, through Electricity Market Reform, put in place the framework to deliver to this standard. Our scenarios therefore flex the two variables of affordability and sustainability. 7.2 We believe our modelling used for scenario development is appropriate and fit for this purpose, although we continually seek to review, benchmark and enhance our models as new information and data becomes available. The development of our FES scenarios is supported by a robust process of stakeholder engagement to ensure continual review and improvement in the quality of our analysis and enable the delivery of our data rich scenarios. To improve future modelling and access to data, National Grid supports the continued commitment to greater transparency of information.
8. What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
8.1 We recognise in our FES publication that the future comes with uncertainty, and as we move further out into the future this uncertainty increases. To analyse and encapsulate that uncertain future we create a series of scenarios which cover the range of credible futures, covering both affordability and sustainability while maintaining a resilient security of supply. 8.2 Looking beyond the steps already noted, part of our assessment of the UK’s future energy landscape has shown that decarbonisation of the existing generation fleet will come with the potential of connecting substantial volumes of low carbon and renewable technologies to the UK’s electricity transmission system. The effort to meet this decarbonisation target will need sustained, confident investment; and the key to inspiring this investment is stability and certainty of the UK and EU legislative and regulatory environment.
9. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience,
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whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
9.1 National Grid’s FES Scenarios do not currently feature any significant game changing technologies that could have a revolutionary impact on our electricity network infrastructure and its resilience in the 2020s. Technologies that we envisage would make a significant contribution to the system’s resilience in terms of security of supply and required to meet the electricity supply set out in our Gone Green and Low Carbon Life scenarios. They are all market ready with the exceptions of Carbon Capture and Storage (CCS) and electricity storage beyond the pumped storage currently available. 9.2 CCS is an innovative technology which will help with the resilience of the system. Whilst addressing greenhouse gas emissions it will also enable fossil fuels to continue to be used as part of a low carbon generation mix and serve as an aid to balance variable forms of low carbon generation. CCS uses established technology in an innovative way to capture, transport and permanently store CO2 emissions from fossil fuel power stations and industrial emitters beneath the sea bed. Flexible power generation with CCS enables the maximum levels of renewable and nuclear energy in the lowest cost way, with lowest emissions. 9.3 Whilst CCS generation is not yet proven on a large scale, in March 2013 the Peterhead and White Rose Projects were named as the two preferred bidders in the UK CCS Commercialisation Programme Competition. To bring down costs and allow CCS to be more widely used, the full chain of capture, transport and storage needs to be built and operated on a commercial scale. Analysis also shows that annual household energy bills could be £82 lower by 2030 with CCS in the energy mix than without121. 9.4 The two very distinct projects within the CCS competition would benefit from developing together to create strategically important infrastructure which would accelerate the benefits of a UK CCS industry and supply chain. If both projects were to progress in conjunction with one another, rather than in competition, they could collaborate and share learning, which would create better value for the Department of Energy and Climate Change. 9.5 Electricity storage has great potential to be a game changer in terms of balancing electricity supply and demand if it can be brought forward as a cost effective proposition. Energy storage has the potential to take excess generation such as on a windy or sunny summer day, and store it in multiple places from large pumped hydro stations down to batteries within homes and everything in between; potentially becoming a game changer. 9.6 The ambition to roll out smart meters to all households in 2020 is likely to have little impact on energy resilience on its own. Smarts meters are an enabler for other mechanisms to take effect, in particular smart appliances combined with time of use tariffs. By 2030, our FES scenarios assume that smart meters will continue to have a relatively modest impact.
121 ‘The Economic Benefits of CCS in the UK’ Trade Union Congress and the Carbon Capture and Storage Association Report 2014 http://www.tuc.org.uk/sites/default/files/carboncapturebenefits.pdf.
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10. Is the UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
10.1 Investment in energy transmission provides opportunities to support the UK economy in both the short and the long term, delivering a number of sustainable economic benefits including job creation, export opportunities and a gateway for further investment. In terms of maintaining a resilient low carbon energy system, National Grid does not see a benefit in favouring one technology over another. National Grid is technology neutral. We support the system having a diverse range of energy sources to maintain long term security of supply, and a portfolio of technologies ensures that their individual benefits and limitations are balanced. 10.2 In assessing opportunities for driving economic growth, National Grid has supported CCS over the past seven years and has championed the important contribution that CCS can make to decarbonising the UK’s future energy mix, by enabling carbon intensive industries to reduce their emissions affordably. We have been at the forefront of researching and testing pipeline capabilities for CO transportation and progressing CO storage development. 10.3 A UK CCS industry would deliver economic benefits of £2-4 billion per year by 2030 and create up to 30,000 jobs. There is also potential for growth in the UK becoming a leader in storage technology in Europe. Last year, while taking part in the White Rose competition National Grid completed ground-breaking work to drill the world’s first offshore appraisal well for the storage of carbon dioxide in the North Sea around 65 km off the Yorkshire Coast. 10.4 An additional technology with the potential to drive economic growth and in which the UK could become a leader is interconnection. Increased interconnection to overseas electricity networks is anticipated to aid security of supply and help balance variable forms of low carbon generation. Increasing interconnection is seen to support the cost of maintaining resilience as it is cheaper than building extra generation to improve the diversification of supply and demand. 10.5 National Grid’s analysis shows that each 1GW of new interconnector capacity could reduce Britain’s wholesale power prices up to 1-2%. In total 4-5GW of new links built to mainland Europe could unlock up to £1 billion of benefits to energy consumers per year, equating to nearly £3 million per day by 2020122. Greater electricity interconnection could yield a range of potential benefits to the UK economy and GDP. Through net imports, lower electricity prices to business consumers would reduce input costs, enhance competitiveness and boost household disposable incomes and domestic spending. Through net exports, there is also a significant opportunity for British generators in using interconnectors to access a much wider consumer base across mainland Europe and thus earn additional revenues. 10.6 New interconnector projects would also catalyse a range of additional economic benefits. New jobs would be created from the need to plan, build and maintain the new links and inward investment would be boosted in order to deliver the multi-billion pound
122 Getting More Connected 2014, National Grid http://www2.nationalgrid.com/About-us/European-business-development/Interconnectors/.
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projects. This inward investment could reach a critical mass requiring new industries in the UK to manufacture the substantial quantities of subsea cabling required.
11. Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects?
11.1 Ofgem has put in place several mechanisms to stimulate and fund innovation in the interests of consumers that will lead to developments in how National Grid delivers to our customers and stakeholders. Innovation is an important feature of our RIIO regulation mechanism where our revenue is linked to innovation, incentives and specific outputs. All explicitly funded innovation activity by licensees is made public through Ofgem’s Network Innovation Competition and Network Innovation Allowance funded projects. In addition there are a number of interactions at all levels across our company with government, other industry parties, our employees, suppliers and the innovation community. 11.2 This wide engagement ensures that learning from projects is shared to benefit all consumers. National Grid is playing a significant role in the Low Carbon Network Innovation conference- a showcase for the exchange of information on innovation projects- and has recently published key stakeholder documents on the innovation activities we are taking forward, along with increasing the transparency of who in our organisation to contact to share learning. 11.3 National Grid actively participates in a number of groups and organisations to share industry learning. A key group is the Energy Networks Association and through their Innovation Forum we, and other transmission and distribution network operators, share ideas, research and development learning points and disseminate information to our stakeholders. We produce an annual review of our innovation activities123.
12. Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
12.1 The current energy policy and regulation picture for electricity infrastructure needs to be considered in the context of: Global and European fossil fuel prices that are likely to remain high and volatile large investments needed to meet environmental objectives while environmental
externalities are not yet robustly priced; and other economic factors adding to energy affordability concerns. 12.2 Given this context, vigorous political debate on energy issues which drive ongoing government policy making and adjustment. However, despite the potential for ongoing and even increasing intervention, it remains that the benefits of a market-based energy approach include:
123 Annual Network Innovation Allowance Report 2013/14, National Grid http://www2.nationalgrid.com/WorkArea/DownloadAsset.aspx?id=34778
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The facilitation of a decentralised and efficiently incentivised explore, trial and learn process which offers the best prospects for relevant innovation and efficient implementation;
appropriate cost allocations together with signals to encourage efficient demand responsiveness and energy efficiency; and
the encouragement of private investment at appropriate risk adjusted rates. 12.3 To maintain these benefits, regulators must continue to act in a manner which is consistent with facilitating competitive energy markets, in short, by continuing to abide by the principles of good regulation set out by the Better Regulation Task Force. 12.4 The electricity market is currently the subject of significant change, particularly including the introduction of a capacity mechanism and new support mechanisms for low carbon and renewable energy sources. We consider these to be appropriate interventions and developments given current challenges identified above. In particular, while these measures give greater certainty that security of supply and environmental policy goals will be achieved, the measures are also market compatible as they introduce contracts and instruments that a well-functioning market would offer and trade. 12.5 The facilitation of resilient network infrastructure to support the European market such as the development of interconnection, offshore grids and their integration with onshore network facilities require greater coordination. We welcome Ofgem’s Integrated Transmission Planning and Regulation project and initiatives in this area. 19 September 2014
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National Grid and the Energy Networks Association (ENA) – Oral evidence (QQ 53-68)
Evidence Session No. 5 Heard in Public Questions 53 - 68
TUESDAY 4 NOVEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Viscount Ridley Lord Rees of Ludlow Lord Willis of Knaresborough Lord Winston ________________
Examination of Witnesses
Mike Calviou, Director of Transmission Network Service, National Grid, and Tony Glover, Director of Policy, Energy Networks Association (ENA)
Q53 The Chairman: Welcome to this evidence session. We are most grateful to you for your help. I should just note that we are being broadcast on the parliamentary television
channel and webcast. That might be relevant. First, I would ask you to introduce yourselves
for the record, and if there are any words of introduction you would like to make before we
start with our questions, do feel free to do so. Mr Calviou.
Mike Calviou: Good morning. I am Mike Calviou. I am director of transmission network service at National Grid. I work in the system operator part of National Grid that looks at balancing supply and demand in all timescales and planning the future network.
Tony Glover: I am Tony Glover, director of policy at energy networks association, the trade association for the gas and electricity network operators, both at transmission and distribution level.
The Chairman: Thank you very much. Are you content for us to go straight into the questions?
Mike Calviou: Yes.
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The Chairman: Let us do that. You will know that we have taken several days of evidence about the capacity margin, and indeed National Grid has recently published its assessment as to where we are. The long and short of it is that we know that the margins are rather tighter than they have been in the past although, to be fair, the record over the last 30 years or so has been perfectly respectable. Nevertheless, the capacity margins are now tight. Would you like to say whether you feel that this will affect the resilience of the electricity system? What, in an ideal world, would you think the de-rated capacity margin should be?
Mike Calviou: It is important to say that we at National Grid spend the whole time planning for resilient operation of the system, looking at what might go wrong and trying to make sure that the really high levels of resilience that we have traditionally enjoyed are continued. We are facing tighter margins in the coming winter than in the last few years although, if you look over a longer term, we are still at levels that are higher than they were, for example, in the early 2000s. Even though levels are tighter, we feel that, given the action that we have taken, margins look manageable for this winter. We are not complacent. We spend the whole time looking at risks. There are some risks this winter, which is why we have purchased the additional supplementary balancing reserve for this winter, but overall we feel we have the right tools in place to continue to manage the system at a very high level of resilience.
The Chairman: Mr Glover, would you like to comment?
Tony Glover: I have nothing to add to that in terms of what Mike said for the National Grid.
Q54 The Chairman: I would go back to National Grid then and ask whether you feel that you are sufficiently well informed by the generators. Of course we recognise that the generators themselves have problems because with the distributive system of generation now, with a lot happening in a way which is not the traditional pattern, that does add a complexity to the procedure. To what extent does that cause concern to National Grid? Are you satisfied with the information that you are receiving?
Mike Calviou: We have a lot of tried and tested procedures in the industry for communication, particularly under the Grid Code. Generators are required to submit declarations of their availability for coming years but also, particularly as we get into a winter period, they are giving us weekly forecasts of their availability and when they might have plant on maintenance. We are very happy that the information we get is of sufficient quality and accuracy for us to plan the system. Effectively, all of that industry information is what we then use to provide real-time reporting to the market as well as providing the basis for the recent Winter Outlook Report that we published. We also do a lot of consultation with the industry, so if people have particular issues or identify risks, they have opportunities to raise that. We are continually dealing with large amounts of information but generally we think the information flows work.
Clearly, we are always dealing with the risk of unexpected events. When we talk about margins they are what we call “de-rated margins”. They allow for a typical level of breakdowns, but what we always have to assess is, “Could we have an atypical level?”. Obviously, in the last few months, we have had a number of incidents happen on the system that have led to some concern but we think, having assessed all of those, that we have taken the appropriate action given the risks that those events have presented.
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The Chairman: Last week, we took evidence from Professor Dieter Helm of Oxford. When we asked him what the capacity margin should be, he said, “10% at the very least but perhaps not as much as 20%”. You appear to be quite content with a figure that is much reduced from that. Do you think he is right?
Mike Calviou: I do not know exactly what he said, but I think you have to be clear on what definition of “margin” you are talking about. In the past—certainly in the 1990s—we used to talk about gross capacity margins. Back then almost all the generators we were relying on to generate electricity had the same typical reliability rates, so we tended to talk about the gross margin of total gross capacity and a figure of around 18% to 20% was the number the CEGB tended to plan to under its generation security standard.
With the change in plant mix that we have seen in the past 10 to 15 years, particularly the growth of intermittent renewables, that methodology did not work anymore so we have moved to what we call a “de-rated margin”. For all of the generators attached to the system we have a “de-rating figure” that basically allows for a typical level of unavailability, due to breakdown or due to the fact the wind is not blowing or the sun is not shining, depending on the type of renewables. When we now talk about de-rated margins, an average amount of breakdown is already effectively taken into account. That is why we now tend to talk about margins of around 5%. For this coming winter, the market has delivered a 4.1% de-rated margin. We have taken action with our supplemental balancing reserve purchases to increase that to a 6.1% margin, and we think that is a level that we can manage the system with this winter.
I do not know whether Dieter was talking about a gross, net or de-rated number. I think over 10% on a de-rated basis would be a very, very comfortable margin, which I would be surprised if the market was consistently delivering because at that level there would be some generators that would probably never run.
Q55 Lord Rees of Ludlow: Your projection for next year is tighter than this year already and, given that we have tightened the margin this year by nearly 3%, does that not make you even more worried about what might happen next year?
Mike Calviou: For the last couple of years, we have been flagging that there is definitely a challenge coming. We have been spotting the 2015 to 2016 challenge coming for a number of years, but this year it came a year earlier because of some of the events I have mentioned. Ultimately, what margin the market delivers will depend on decisions that a number of generators will take, but we know that there is a certain plant that will be closing because of emissions legislation and so will not be available next winter. Because of that, we have already opened a tender for additional supplemental balancing reserve for next winter, both demand side and generation. We have just opened a tender for that now, which gives us the opportunity, for example, to contract plant to bring it back from mothball for next winter if required. We are going to do one tender with a 12-month notice with the possibility of then running an additional tender much closer to next winter, probably some time over next summer or autumn. So there are some challenges for 2015 to 2016, but we have the tools to manage them. I am not complacent, because we would never be complacent with these things, but at the moment it looks manageable.
Lord Rees of Ludlow: If I could follow this up and go back to Dieter Helm’s view. Perhaps he is concerned about this because in many areas we find that the high-consequence, low-
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probability events happen unexpectedly and more often—in the financial sector and with nuclear accidents and things like that. Given that this does seem to be a non-zero risk, would it not be better to have a slightly larger comfort margin?
Mike Calviou: I think that is a great question. Ultimately, it is government policy that sets the parameters we work within. The Government have set a LOLE—loss of load expectation—of 3, which forms the basis of all our decision-making. For this winter, once you count our additional supplemental balancing reserve, LOLE is actually 0.6, so it is quite comfortable. The key thing to say with that, though, is that LOLE is effectively a measure of how often we would have to get into emergency measures which we cannot count on.
We have a number of ways of managing the low-probability, high-impact events: we can call on what we call “max generation” from generating plants; we can call in emergency assistance over the interconnectors; and we can work with the distribution networks to manage demand down, either via voltage management or ultimately by some sort of load control. We have all those tools there to manage the emergency events. We clearly do not want to be doing that too often but we feel that, if those extreme events do happen, we know what we are doing and we plan for them. That is a core part of our role.
Q56 Lord Broers: I have two points, Chairman. First, on that particular issue, Professor Helm was suggesting that the low margin drove the price up and that it would actually mean much lower cost if we had a broader margin. Do you agree with that?
Mike Calviou: I guess he is right fundamentally: in any market, if there is less supply, then you would have thought the price would go up. We run a market-based system for electricity generation and demand. As National Grid we will only intervene once we have seen what the market delivers by itself. Ideally, the market should find some sort of equilibrium between supply and demand. If there is the very large margin that he talked about and the price goes down, what you will then find is some generators struggling to make enough money to stay open, pay their staff and pay all the other fixed costs of keeping a generating station open. The reason the margin has come down is because the economics of some of that marginal gas and coal plant have been very unfavourable. We know that there are generators out there running at a loss, and that is clearly not sustainable.
The price will go up and down as the margin goes in the opposite direction, and that is what you might expect with a market in anything. Given how important it is that we have a resilient electricity system, it is important that we have those tools that I have talked about, in order to manage it if the market does not deliver quite enough capacity. We try to do that in a way that does not distort the market too much but recognises how important electricity resilience is to society.
Lord Broers: I have a point of clarification. In some of your literature you refer to the overall generation capacity as 71.9 gigawatts and yet in your report you refer to 86 gigawatts. Is that 86 the un-derated number?
Mike Calviou: Yes. That is probably the total growth capacity, including all the renewables.
Lord Broers: The non-derated renewables? On the third page of your report you refer to 86 gigawatts as the growth generating—
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Mike Calviou: So 86 would be the total amount of large generation capacity—either connected to the transmission system or sufficiently large that we are notified about it—in embedded generation.
Lord Broers: That is a huge difference.
Mike Calviou: Yes, but that would include a number of gigawatts of wind that we would then be de-rating by—
Lord Broers: If there was a 5 gigawatts turbine in the 86, you would count that as 5 rather than a fifth of that?
Mike Calviou: Yes.124
Q57 Lord Dixon-Smith: I think I have a reasonably clear picture of the management on what I would call the supply side of the business, but an increasingly important part of managing supply is actually going to be demand management. Could you explain in a bit more detail how demand-side management works now and how you see that developing? Given the intermittency in growth that is going to happen and that sort of thing, this is going to become a more and more significant aspect of your work.
Mike Calviou: You are absolutely right: demand side is really important, particularly for managing some of the future challenges. We have always looked to buy services. We procure a number of what we call “balancing services” to help us manage the grid: some of those services are for a response within seconds, some within minutes and some in longer timescales.
One of our key services that we buy is something called “short-term operational reserve”, and we have been buying that service from demand side for a number of years. Currently, we have around 2 gigawatts of what we call “non-balancing mechanism” providing that service—that is, not traditional generators that are obliged to play in the balancing mechanism. That will be onsite demand reduction but it could be some onsite generation as well. We are very used to dealing with demand side—that can be steelworks or cement works; in the past we have done a lot with aluminium smelters—so we are very familiar with putting in the arrangements to use that sort of large industrial load.
Going forward—and we have seen a bit of this with our new demand-side balancing reserve—we would like to open that market up and make it more available. Clearly, new technology offers a chance to give us more access to commercial load. There is a lot of load out there—for example freezer load in supermarkets—which feels as though you could be able to actively turn that down at the requisite moment and, for not much impact on the customer’s business, they might be able to provide a useful service. We have been working directly with those customers and with aggregators that are very enthusiastic about developing this area. The demand-side balancing reserve for this year was a pilot; it was the first time we have done it. We have about 300 megawatts of new additional demand side, but we see that as a first step and we would like to develop a lot more.
Going forward, looking at the capacity mechanism, we would want more demand side to be able to play in that. There is a lot of discussion going on with the Government about how to
124 It emerged after the evidence session that the literature referred to by Lord Broers was actually written evidence submitted by the UKERC, not a National Grid publication. National Grid’s 2014 Winter Outlook Report sets out that the un-derated generation capacity available for this winter is 71.2 GW (page 6).
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make the capacity mechanism rules sympathetic and help facilitate demand side to play. There have been some challenges and some debate and I think we will probably see some of the rules around demand-side participation evolve over time to help them come in.
Once you look at the longer term, looking at various smart grid technologies, we would hope and expect to use the ability of smart controllable technology to continue to grow that demand side. Ultimately, in the future, if we could have access all the way down to domestic demand—whether that is electric vehicle demand, fridges and freezers in people’s homes or whatever—and the ability to switch and profile that as a service, then that would give us a great tool with which we could help balance the system in the future. Some of this is probably getting five or 10 years into the future.
Q58 Lord O’Neill of Clackmannan: On the 5% margin that you suggested, it was put to us last week that, at the moment, we are more dependent on coal than we have been for a long time and therefore there are gas stations lying idle. What was not clear from last week’s evidence from Helm was whether or not the gas-fired power stations, which traditionally can be fired up relatively quickly, are being kept at a state of maintenance that would enable to come into the system very quickly. What is the quality of the evidence you have to suggest that that would possible? Are we perhaps not looking carefully enough at this gas issue?
Mike Calviou: Both coal and gas, if they are available on the system, can be very flexible and can provide a very similar flexibility service to us. You are right that, at the moment, the economics mean that coal tends to running ahead of gas and so a number of gas stations are not running a lot. That leads to some of the economic challenges that we spoke about. For example, Barking combined cycle gas turbine announced its closure earlier this year. So, yes, there is some gas-fired plant that is effectively struggling to make its way. We get some information from those generators about what it would require if we were to effectively require them to come back under, for example, an SBR contract. If a generator closes this year, bringing them back quite quickly is relatively straightforward; if a generator closed two or three years ago, clearly the odds are that they will be in a less good state. There are other what I would call first-generation CCGTs that have closed and will probably never come back. I think the key thing, though, is that the capacity mechanism is, in the long term, the mechanism to deal with all of these challenges. The capacity mechanism is the route for us to make sure there is enough flexible capacity, whether it coal, gas or whatever, available on the system against the Government’s required standard.
Lord O’Neill of Clackmannan: Do you have the information to enable you to be comfortable with a 5% margin, taking into account the problems that you would have with the gas sector, which has not been fully operative? I think that is the point.
Mike Calviou: We have full information on everything in the 5% margin, or the 4.1%, plus the additional SBR, and we know it is ready to run. On the SBR, we will be doing regular test runs to make sure it is fully able to run. The stuff that we would have a bit less information on is the stuff that we are not counting in the margin, which we might want to bring back in future. We are fully confident that any stuff that we are relying on is able to run.
Q59 Lord Peston: I must say, as background, that the more evidence we take in this area the less I understand, but that is another matter. I am still trying to work out how this market works. I understand that you sign contracts with the generators and that these are a
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variety of different contracts depending on what they are committed to for you. Is that right?
Mike Calviou: The bulk of the market is nothing to do with National Grid. Effectively, energy suppliers, who buy electricity on behalf of their customers, will be contracting with the generators and 95% of the market will be through that market mechanism and that—
Lord Peston: Just to interrupt you, does that not go through the national grid then?
Mike Calviou: It physically goes through the national grid—
Lord Peston: Yes, physically, that is what I mean.
Mike Calviou: However, contractually it is nothing to do with us, effectively. We rely on the market to do that. When National Grid acts, what we do is we buy specific services to help us balance the network in real time. We make sure that, if a number of generators all have a technical problem at short notice, we have enough reserve that we can use to deploy in those situations. We buy the balancing services and various types of operational reserve to help us with that. What we have now done for this winter, because of the tightening margins that we have discussed, is that we have bought some additional reserve to ensure that we are resilient for this winter, given the fact the market appears to have delivered a margin that is lower than we were probably ideally comfortable with.
Lord Peston: If your decision-making then turns out to be erroneous, who is responsible? Who has the finger pointing at them and who gets the sack? You are not perfect. You must make errors.
Mike Calviou: We do, but ultimately we work within parameters set for us by the Secretary of State. The LOLE equals three parameters, and we will make decisions within that. We probably always try to slightly err on the side of caution—that is why we enjoy a very high level of resilience—but ultimately we are accountable for balancing on the day, in the short term, within the framework that has been set out by the Government.
The Chairman: Lord Peston, your question is bringing us toward the balancing services, which is what I think Lord Broers was going to ask about.
Q60 Lord Broers: You have talked a lot about this but I would like to put the question anyway. How will the new balancing services work and will they be sufficient to balance supply and demand over the next two winters? Further to that, given that these services have not been tried and tested, how certain can we be that the new balancing services will be effective? Has National Grid needed to procure additional balancing services in response to the recent power station outages, including the most recent at Didcot?
Mike Calviou: We are feeling reasonably confident about the new balancing services. If we divide them into two, first, there is the new SBR, the supplemental balancing reserve, which is existing power stations that would probably otherwise have closed. It is a new service but it is ultimately known technology. As I said, we will be running the plants to make sure that they are technically able to run. You never rely 100% on one generator, on but we take that into our calculation.
The new demand-side balancing reserve, of about 300 megawatts, is new. It is less tried and tested, but we are not overly relying on that. We see that as a pilot but, because we have
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experience of other demand-side services, we know that when we instruct demand side we actually see a measurable effect. We are pretty confident about that.
The only thing I would say is that although we are set up in a good position for this winter, I cannot be as confident for next winter yet, purely because we have not actually bought all of what we are probably going to need for next winter. At this moment, I cannot be quite as definitive about 2015 to 2016 because we do not know how much we are going to have to buy and exactly what we are going to buy. But generally, whenever we bring in a new balancing service, we do it in a way that takes into account how reliable it is. The whole way we achieve very high resilience is to have lots of options and lots of optionality.
Lord Broers: Did you have to bring them on for Didcot?
Mike Calviou: Didcot, the fire at Ferrybridge and the concerns around the availability of the nuclear stations at Heysham and Hartlepool, are all factors that we took into account that ultimately led to us buying the supplementary balancing reserve. The good news on Didcot is that it is two units of about 700 megawatts: one unit was not affected by the fire at all and the unit that was affected by the fire has already come back at half load, and we understand that it is likely to be able to increase its output over the winter. So even though Didcot was a very high-profile event, its actual impact was probably overstated.
Lord Broers: The downside of all of this is it costs money, does it not? Have you made an estimate of how much it is going to push people’s electricity bills up?
Mike Calviou: The additional cost of the supplemental balancing reserve this winter will be less than £1 per customer on their bills.
Lord Broers: What is your assumption of what the bill is?
Mike Calviou: That is against the standard—I cannot remember what it is.
Lord Broers: It would be much more useful to have it.
Tony Glover: It is about—
The Chairman: Mr Glover, would you like to comment on that one?
Tony Glover: Sorry, yes, forgive me, Lord Chairman. About 20% to 25% of the bill comprises network costs, so the £1 is in that context of that.
Lord Broers: I wish you would not give numbers like “£1”. That means nothing to me; I want to know the percentage.
Tony Glover: It is about 38 pence a day. That is the total cost to the network.
Lord Broers: That is even worse. I want to know what percentage change there is going to be in somebody’s electricity bill.
Mike Calviou: The standard bill that we tend to work off on electricity I think is about £600-and-something a year, so less than £1 a year is less than 1% a year.
The Chairman: All right. We can do the maths on that I think.
Q61 Viscount Ridley: Can I move you onto the capacity market? The medium-term plan is to make sure that there is capacity available to keep the lights on; not necessarily operating but in the background. One of the concerns that has been raised—and I think we are going to hear more about it in the next session—is that there is a risk here that we become too
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generous, that we procure too much in the way of capacity and that, as a result, we end up with an oversupply of capacity in the background. What is your comment on that?
Mike Calviou: I think there is a risk. Clearly, whenever you are buying stuff four years ahead, you need to make some sorts of assumption. I think the particular risk that people have highlighted is that in the first capacity mechanism we have had to make some assumptions around interconnectors and what the interconnectors to other countries will be doing. We believe we have made some sensible baseline assumptions, but the key thing to recognise is that in all our modelling, we look at sensitivities from quite high exports across the interconnectors to quite high imports. You would expect—I think this is probably what some people have said—in a period of system stress on our network, to get higher imports into this country but we also recognise that some of our neighbouring European countries may also be short at the same time. So it is trying to make a balanced judgment. I think the right answer in this is that the Government are currently working on a mechanism to allow interconnectors to participate directly in the market rather than us having to just make an assumption about what they are going to be doing. They are working on that at the moment. We hope for that to be in for the capacity mechanism that runs for 2019, so it is really an issue for the first capacity mechanism in 2018.
The other thing to say on that is that we have designed it so that there is a small amount of capacity that has not been procured for four years ahead and is being left, basically, for a one-year-ahead supplemental auction. That allows for some fine-tuning nearer the event. In particular, if we have been too conservative, and it is clear by then that we have been, that can be adjusted for. I do not think there is a very significant risk that we are overprocuring. Given all of the risks we are talking about, it probably makes sense at four years ahead to, if anything, err on the side of slight caution.
Q62 Baroness Manningham-Buller: I would like to turn to you, Mr Glover, and ask you about the resilience of the networks. Obviously, we have had a certain amount of flooding and storms, and I would like to ask you a twofold question first off. What are the lessons you learnt from those, if any? If you have learnt the lessons, what changed as a result? In other words, what was implemented as a result of those lessons?
Tony Glover: There are two aspects to that, as well as perhaps something around how we dealt with the situation at the time, which was an incredibly challenging situation, and a national picture if you are looking at the Christmas storm in particular. One thing to bear in mind, against the backdrop of what was a very bad time for a lot of people, is that over Christmas we saw about 750,000 homes impacted.
Baroness Manningham-Buller: You mean they had no power?
Tony Glover: They had no power, but about 95% were restored within 24 hours. Obviously a large number of people were affected but the vast majority, 95%, were restored within 24 hours. It is against that backdrop of a national picture of a problem that was cutting right across the country. Usually, these weather events—which you can say it is climate change, but they are just bad weather events that will happen and which we cannot necessarily predict—do not impact in the way it did at Christmas, across the whole country. That was quite an issue in terms of the procedures that we would normally have around mutual aid such as where, if you have the south-west of England impacted, you would have Scottish network companies coming down to help and vice versa. With the situation we had, of a
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moving weather front, in fact distribution network operators were not able to help each other. Of course this was coupled with a serious flooding issue as well. Given that this happened right in the middle of the Christmas period, you then see the nature of the difficulty. I wanted to identify that and talk about the reality of what actually happened, in terms of who was restored and who was impacted.
The lessons learnt were twofold, and we experienced only in February this year a repeat, to some extent, of some of that bad weather impact. Some of them were very short-term lessons around communication, which we have put into operation. That is an absolutely critical issue. At the end of the day, network engineers can only work as fast and as safely as they can work. To be absolutely clear, these were people from their local communities; people themselves who were actually without power. In fact some of them were restoring others when they themselves were without power. So there is no question about the commitment of the industry itself. The issue was around communicating to the public what the situation was and how long they were going to be in that situation. That was a challenge, I must admit.
Baroness Manningham-Buller: I am sure communication helps, but were there enough resources and enough people going to help restore the power? What you describe in the past could happen again next year.
Tony Glover: Absolutely.
Baroness Manningham-Buller: Will you have more people able to restore the power, at least in practice?
Tony Glover: Absolutely. In terms of what the companies have done—and bearing in mind that this was a particularly difficult time, being Christmas—what has happened is that all the DNOs have a process now that absolutely ensures that there are enough resources available in order to do what is necessary.
Baroness Manningham-Buller: People?
Tony Glover: People. Just to repeat, that is against the a challenging backdrop: no matter how many people you have, you cannot, for instance, restore power to an area that is badly flooded, for obvious reasons. There are lots of challenges there that are impossible to deal with and you can only give people information, and then you can only give them so much information. So there is the communication aspect. Something that will be brought in at the latest by April 2016 is a single national emergency number. This will be the third such emergency three-digit number brought in since the police and the NHS brought in their own. They took nine years to bring theirs in; we are hoping to have ours in within two years. That will help because anybody faced with a power outage situation will be able to phone up, and they will be put straight through to their distribution network operator who will be able to tell them exactly what the situation is. That is another big learning point.
Baroness Manningham-Buller: Looking ahead to further unexpected events and possible climate change, what have you thought about and what have you planned for improving the resilience of the transmission and distribution services?
Tony Glover: A lot of work has been going on well in advance of these recent weather event. Work is ongoing with the Department for Environment, Food and Rural Affairs, the Environment Agency, the Climate Change Committee and others, looking at adaptation, looking at how we make the network more resilient in terms of flooding and—particularly
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appropriately with the Christmas winter storm situation—looking at wind patterns as well. Wind patterns are not particularly looked at in terms of climate change but, nevertheless, they have a serious impact on the network. We have been working with the Met Office on that and also with the University of Newcastle to look at what wind patterns are likely to be and making some predictions about where we need to build more resilience into the network.
Baroness Manningham-Buller: What are those predictions? Give us a few of them.
Tony Glover: It is more geographically located, I think, and about the type of wind we might face. Potentially, it is going to get windier and we will have to make the network more resilient where that is the case. Indeed, in parts of the United Kingdom—in Scotland, for instance—the network in parts is more resilient at distribution network level because of the nature of the weather that they experience. We will deal with that where it is appropriate, but of course we have to see this against the backdrop of having to do this as efficiently as possible and being very much aware of the impact on customers’ bills. Dare I say it, as I speak to you now, in another place there is an inquiry currently going on into the cost of networks and questioning how much our networks actually cost. We have to see it within that context.
Q63 Baroness Manningham-Buller: I have one final point. One of the things I have learned about in this inquiry is a thing called local resilience forums, which I was completely unaware of. What is their value?
Tony Glover: We work very closely with the distribution network operators. National Grid works very closely with the local resilience fora and has been now for a number of years. They were brought in under the Civil Contingencies Act, I think 10 years ago or so. The very positive side of them is that it is about communication with the key local stakeholders—local authorities and so on. It is about that communication with police, with the hospitals and the other emergency providers, the category 1 providers as they are described. That aspect is very good.
The challenge that we sometimes face with them is the particular localised geographical location of the fora. Sometimes, for more of a regional network operator, it would be useful to have more of a regional view as well. That is something that we would like to see but, in terms of being a very positive addition, yes, there is a lot of work carried out on particular scenarios. One big area for us, and something that was very much on every network operator’s mind during the recent winter storms, is the impact on vulnerable customers and identifying vulnerable customers. For instance, working with the NHS and working with local hospitals to understand who is currently in their home, and who may be temporarily very vulnerable, that we might not necessarily know about. That is absolutely critical so that we know what happens in an outage situation.
The Chairman: One plea I would make, as one of the 5% who was not connected within 24 hours, is that you do learn lessons on communications.
Tony Glover: I am aware of that, Lord Chairman.
The Chairman: There is no excuse nowadays for not texting up-to-date information, and to have information that is 24 hours out of date is exacerbating a problem. I think there is an awful lot of good will from consumers if they know what is happening: they know it is
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Christmas and they know you are stretched, but it is quite unacceptable to have information that is out of date.
Baroness Manningham-Buller: Can I just add to what the Chairman said? Recently I had a power cut at home and I was told within two minutes of it happening how long it was going to last for. The fact it lasted for an eighth of that time made me a very happy customer, not a cross person because my kettle would not work. People will put up with a lot if you communicate, and that system that works where I live should be national.
Tony Glover: Just to echo that point—I completely accept what you are saying, Lord Chairman, and indeed I have spoken to a number of people who were in a very similar situation to yourself—communication is absolutely at the heart of this. We cannot necessarily get you back on as quickly as perhaps some might hope, but we should be able to tell you what the situation is. We cannot always tell you how long but we can give you some sort of indication, particularly in very difficult circumstances. But your point about getting that information to you as soon as possible is very well made.
We are doing a number of things. This is not just about providing a single national emergency number at a point in the next year or so but also gathering and garnering as much information as we can from the suppliers about your communication details so that, when we have contact with you and when we can get hold of information about your telephone number or your mobile number, we will then be able to text you. We are keeping that information and making sure that we can use that to get back to you when we need to because you are absolutely right.
Q64 Lord O’Neill of Clackmannan: Part of what we are looking at is the changing character of generation. Obviously decarbonisation of generation is going to be of considerable significance, and part of this will be interruptible generation or distributed generation. When you have been looking at your various scenarios in National Grid, how has the network resilience factor been accommodated in the models that you have created in the light of the scenarios that you have painted?
Mike Calviou: We create these future energy scenarios in order to try to spot these challenges coming and give us a way of thinking about the future. You are certainly right that the changing nature of generation in a connected network does create some potential future challenges, particularly intermittency. However, there will also probably be less plant that has heavy inertia on the system, so there will be rotating machinery that has the ability to absorb distortions to the system.
With that, on the back of our future scenarios, we have produced for the first year what we call a system operability framework, which we have just consulted on. It is effectively a document that says, “In these future scenarios, these are some of the challenges we would have in operating the system and, therefore, these are the sort of services we might need to help us”. In scenarios with a mix of very large, inflexible nuclear plant and lots of intermittency, we will probably need a lot more balancing services that are probably from non-traditional sources, whether that is demand side, storage, increasing interconnection to other countries or some other solution that someone will come up with that we have not thought of yet.
The idea of our system operability framework is effectively to flag these things coming five, 10, 15 or 20 years in the future and to allow the market to respond and bring these things
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forward. We do not see anything on the immediate horizon we cannot manage. We do see challenges in the 2020s and 2030s that could emerge in different scenarios, and what we are trying to do is flag those early enough that the market can respond.
Lord O’Neill of Clackmannan: As far as distribution is concerned, we are going to have changes as a consequence of heat pumps, electric vehicles and the like. How well placed are the distribution companies to meet these challenges in terms of the capabilities of their staff and equipment?
Tony Glover: Potentially you are looking at a doubling in electricity demand over the next few decades. The impact of that obviously is quite considerable on the distribution network, so we need to think differently about the network. Network companies are working together collaboratively where possible, given the regulatory framework, to look at how we deal with the challenges of electric vehicles and of increased electrification of heat. At the same time, obviously, we are looking at microgeneration in increasing amounts, whether it is local community-generated energy or in individual homes through things like solar PV, and the impact that that has on the network. Not only are we looking potentially at a big increase in demand, we are looking at the impact of new sources of generation on to the network, making it a far more active network at distribution level, something I know you will be very familiar with, Lord O’Neill.
On top of that, we have to think about distributed generation, so renewables connecting directly on to the distribution network. How do we deal with all that? How do we do that without just putting in lots more wire and, therefore, adding to the cost to the customer? The way we do that—and it is a much mis-bandied word—is to think about it in a smarter way: having smarter networks, using ICT, using remote access and looking at how we can think about the network in a way that we have not done or had to do in the past. Something that has helped drive that, support it and facilitate it has been the Low Carbon Networks Fund, which is something that was brought in by the Government and Ofgem. There has been £500,000 of investment in projects, looking at a whole range of things from storage through to how we manage new distributor generation, how we deal with the customer and how we can deliver real reductions in demand in the community. For instance, one of the projects in the north-east has seen a 10% shift in peak demand by the families and local households that have been part of that project. That has big positives for the network itself in terms of the impact in the peaks on the network and the load, but also it means that we can facilitate demand-side management for the future, which plays up to Mike’s level and helps support that. There is a lot of work going on on that. We are working through the Smart Grid Forum, and the Energy Networks Association leads on a number of those workstreams. We are also sharing that information. We had a major conference last week in Aberdeen, with about 800 people attending from among the energy community and people interested in community energy groups. We are disseminating that information and getting as much learning as we can.
Q65 Lord O’Neill of Clackmannan: Yesterday’s Financial Times had a very encouraging report for the car industry about new lithium batteries. Obviously this is about headline grabbing, but it could be a game changer. Given the glacial speed at which the use of electric cars has expanded in the UK, would we be capable of meeting a demand that could be created in a relatively short time for this kind of battery-charging facility? Could we do it if we were called upon?
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Tony Glover: Could we facilitate electric vehicles?
Lord O’Neill of Clackmannan: Yes, on a big scale. At the moment there is a natural hindrance to them in terms of charging and the life of the batteries.
Tony Glover: Absolutely. There are a number of issues. There are also safety issues as well, which is something absolutely at the heart of everything we do. We have been working with OLEV, the government body responsible for electric vehicles, with the Department for Transport and with the industry itself— the SMMT, the manufacturing organisation—to look at the safety issues and how we can help facilitate this. I will be quite frank with you that there are still a number of issues. But is it deliverable? I think in the longer term it is.
In terms of some of these technologies, as Mike said earlier, we are currently going through the electricity distribution network price control review, ED1. We are probably looking out to ED2, in the mid to late 2020s, before we see some of the benefits of some of this type of technology.
Mike Calviou: The only thing I would add to that is we probably see as much opportunity with electric vehicles as challenge. If there is a sharp kick-up in electricity demand, clearly that would require investment throughout the chain, in networks but also in new generation capacity. We would expect to see that coming with enough notice that the market could respond. Electric vehicles offer quite a few exciting opportunities for controllable demand side that we can then use to manage some of the other challenges. I see electric vehicles as both a challenge and opportunity.
Lord O’Neill of Clackmannan: One last point: the increasing dependence on the networks will obviously make it attractive to potential terrorists through cyberattacks and what have you. What are the network companies doing to counter these risks? Obviously we do not want you to tell us all your secrets but could you maybe give us some reassurance?
Mike Calviou: We take all types of risk to our network very seriously, including risk from terrorism or cyber. We work very closely with the Government and, as you said, there is probably some detail that it would not be appropriate to share. We have done physical investment, in terms of resilience against our key sites, and we absolutely look at all of our key systems and work with the Government and with other organisations in high resilience areas, such as the banking and defence industries, to share best practice techniques to deal with this. There are obvious things you can do about having separable networks and making sure there are no single-point failures.
There is an entity called E3C, which is the Energy Emergency Executive Committee, which is a collaborative forum for the energy industry sharing best practice around all sorts of resilience. It set up a committee around cyber that National Grid chairs. Effectively therefore, we are leading the group working across the energy industry that is looking at all these risks and sharing best practice. It is a challenging area and certainly, as grids become smarter in the future, there will be more challenges, but I feel as though we are set up to manage them.
Tony Glover: Just to reiterate that from a distribution network perspective, as Mike said, they are working very closely together. In fact there is a project under the LCNF that is looking at this very challenge.
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Q66 Lord Patel: My question relates to the recent Ofgem settlement for National Grid. What effect do you think that is going to have for network companies’ ability to maintain system resilience or, for that matter, plan for the future?
Mike Calviou: We accepted the RIIO price control from Ofgem. Whenever a price control like RIIO is negotiated inevitably we will put forward our view of what we need to spend in the future and our regulator rightly will challenge us. They did challenge us to make more efficiencies than we originally proposed. We ultimately felt we could manage those and deliver on them, so we feel confident that we have the right resources. Ultimately, however much Ofgem fund us, it is our obligation to meet our licence requirements and to make sure we have appropriate skills and expertise.
We have recently been heavily recruiting apprentices and engineers in both electricity and gas because, given the amount of investment required in the network, we probably need more resources. It is something we spend an awful lot of time thinking about. We certainly worry about this country not producing enough engineers, and we do have to do quite a bit of overseas recruitment, but ultimately we realise that it is our job to make sure we have the right resources in place, including the right people, and we think that we do at the moment.
Lord Patel: From what you say, the efficiency savings related to the settlement have not resulted in a manpower loss because you are recruiting. So where have you made the efficiency savings?
Mike Calviou: We were always planning to recruit a lot. We have probably found some ways of recruiting less but still recruiting. We have also made efficiencies in our supply chain. We do a lot of our investment working with construction partners, demanding efficiencies of them. We are making process efficiencies. There are efficiencies in a number of areas and ultimately our obligation is to always find better ways of doing what we require. In some areas, we have identified that we do not need as many staff and some people have been let go, but in other areas where we have new challenges we are recruiting. We are trying to continually update and refresh our workforce.
Q67 Baroness Hilton of Eggardon: Just one final question. The Institute of Engineering and Technology suggested there was a need for a systems architect to help you make the transition to a whole new scenario in the need for electricity. What is your view about that suggestion?
Mike Calviou: We have been involved in those IT discussions. We certainly agree that there are increasing whole-system challenges, as you might call them. Traditionally, the transmission system has tended to run as quite a smart active network and the distribution networks have been much more passive and managed at the interface, but they have not had to look into each other’s areas in too much detail. Increasingly, there are a number of issues where, with a lot more distributed and better generation across the network, you have to look at things on a whole-system basis. So we absolutely agree with that part of the IT analysis.
Is the answer a systems architect? I honestly do not know because no one has fully explained to me exactly what that is and what their responsibilities would be. We think we need to do something in this space. It could be by a better institutional framework. For example, at the moment, there is no formal linkage between the Grid Code panel, which deals with the transmission technical rules, and the Distribution Code panel—it may be something to
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formally bring those together and have a more joined-up approach. We agree there is an issue that needs looking at, so we are working with our colleagues in the ENA and with our colleagues in all the distribution companies on that. Is a systems architect the answer? I am not sure and more work needs to be done to find exactly what that means and where it would fit.
Baroness Hilton of Eggardon: Do you see National Grid as fulfilling that particular strategic role or not?
Mike Calviou: We already do a lot and clearly our role has evolved in recent years with the EMR. Ofgem are currently proposing that we do more in terms of an enhanced system operator role around planning both the onshore and offshore network including interconnectors. I think the distribution issues that it has been suggested a systems architect would look at are beyond our current expertise. So, as I said, it is not obvious to me that you need an entity to do it. There are some challenges, but I would prefer to solve them by correct frameworks rather than setting up yet another body that just confuses accountability.
Baroness Hilton of Eggardon: Mr Glover?
Tony Glover: National Grid is a member of the ENA. As I said at the beginning, we represent both gas, electricity transmission and distribution network operators, so we very much have a whole-system view of the energy system from a gas and electricity point of view. I have two observations. First, as Mike says, we are working very closely together. It has become very clear over the last few years that that is the way things are going. We are doing that and there is that level of communication, thinking about some of the issues that we were talking about earlier. That is happening, I can absolutely reinforce that.
I have perhaps one last cheeky observation about a whole-energy system analysis. I know this is about the resilience of the electricity network but we are looking obviously at the potential future wealth of gas, and one piece of work we carried out was in the area of heat, out to the 2030s and 2050s. Our message here is that we believe that there is a potential role for gas heating way beyond where some have originally seen it and that that, in itself, would help to ensure the resilience of the electricity networks.
There needs to be this whole-system thinking about the electricity network and I think we need to think about gas and the role that gas can play, not just at a generation level but in terms of that whole energy system analysis.
The Chairman: Good, and a last question from Lord Broers.
Q68 Lord Broers: There seems to be evidence that our electricity is more expensive than in a lot of countries in Northern Europe, and certainly more expensive than in America. Do you look at that and try to understand why that is the case?
Mike Calviou: We do look at it, although it is quite confusing whether you are talking wholesale or ultimate end customer. I certainly see numbers across Europe that suggest we are not the cheapest, but we are certainly one of the cheaper countries across Europe. There is no doubt that in the US shale gas has had a massive impact. The price of gas is probably half or less than that in Europe, so shale gas is having an impact. National Grid does have business in the US and we have seen a massive impact from shale gas in driving down gas and electricity bills. There probably is something systematic there that, ideally, the global gas
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market will resolve with an increasing ability to export some of that cheap shale gas from the US, but that is probably still some years away.
It is quite a complicated picture. I do not think there is any evidence that we are systematically more expensive than most other European countries. However, when the wind is blowing and the sun is shining in central Europe—particularly in Germany, given the renewable resources—we do see that the continental European wholesale price tends to be quite cheap, and that is when we tend to see quite large imports across the interconnectors.
The Chairman: We have had some rather conflicting evidence on this and if you do have any hard evidence that you are able to share with us on comparative prices, whether wholesale or retail, whether in Europe or North America, I think that would be very helpful. I accept that we have had some information but we do need to get a better understanding as to where these figures are coming from. If you have figures that we have not seen that would be helpful. This session must now close. I am most grateful to you for having helped us in our inquiry. We will be sending a copy of the transcript for any minor corrections that there may be for the record. Once more, thank you both for your help.
National Grid, Professor Goran Strbac, Imperial College London and The Electricity Storage Network – Oral evidence (QQ 102-113)
429
National Grid, Professor Goran Strbac, Imperial College London and The Electricity Storage Network – Oral evidence (QQ 102-113) Transcript to be found under the Electricity Storage Network
National Grid – Supplementary written evidence (REI0060)
430
National Grid – Supplementary written evidence (REI0060) New Balancing Services procured for Winter 2014/15 Supplemental Balancing Reserve (SBR) Capability Fees : £23.5m Warming/Testing : £6m (estimated) Warming/Utilisation : £0 (unless the service is used in the next two weeks) Demand Side Balancing Reserve (DSBR) Setup Fees : £1.1m Admin Fees : £150k Testing Costs : £1m (estimated) Utilisation : £0 (unless the service is used in the next two weeks) Total Forecast cost for Winter 2014/15 : £31.75m The capability procured is summarised in the table below taken from the attached market report.
Contracted SBR Capability
De-Rated Capacity “Additional” De-rated Capacity
Littlebrook Unit 2 570MW 485MW 374MW
Rye House CCGT 675MW 439MW 0MW1
Peterhead CCGT 780MW 585MW 585MW
Total SBR 2,025MW 1,509MW 959MW
1 Rye House was assumed to be available in our base case used to calculate capacity margins, and therefore not regarded as additional Adding in the DSBR already procured gives the 1.1GW of ‘additional’ de-rated capacity highlighted in the Winter Outlook Report.
SBR/DSBR Quantity De-Rated Capacity Additional De-rated Capacity
DSBR 319MW 136MW2 136MW
SBR 2,025MW 1,509MW 959MW
Total DSBR + SBR 2,344MW 1,645MW 1,095MW
2 DSBR is de-rated to reflect the non-firm nature of the product and that not all the DSBR capability is available/sustainable throughout the evening peak.
National Grid – Supplementary written evidence (REI0060)
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Given a total cost of £31.75m and the volume of De-rated Capacity procured of 1,645MW, this comes in at a unit cost of £19.3/kW which is near identical the where the CM cleared. 13 February 2015
Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Written evidence (REI0026)
432
Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Written evidence (REI0026) The Final Hurdle? Security of supply, the Capacity Mechanism and the role of interconnectors Authors: David Newbery125 and Michael Grubb126 We have recently completed a paper of this title and wish to draw the main themes to the Committee’s attention as they relate to the topic of your enquiry into the Resilience of Electricity Infrastructure. Our note addresses the “generation adequacy” of the system, not the resilience of transmission or distribution systems. Historically, the latter has been the dominant source of problems in electricity supply adequacy; our analysis may be interpreted as concluding that this is likely to remain the case. Resilience of UK electricity to 2020 Much of the policy effort and discussion around UK Security of Supply has focused on the risks, and the potential need for, and design of, a Capacity Mechanism. We consider here a third aspect: assessment of the amount to be procured, specifically in the context of the UK announced intent (30 June) to procure 53.3 GW through its Capacity Auctions for 2018-19. DECC estimated the associated gross payments at £2.6bn annually, but with a much smaller net cost to the extent that generating companies pass through most of the subsidies as lower wholesale prices. A conservative approach to procuring capacity is understandable, but we argue costs can be substantially reduced by deferring some of the associated auctions. At the heart of this is the (somewhat unfashionable) conclusion that the UK electricity is more resilient to the risk of “capacity shortfall” than widely assumed. Our analysis concludes that 53.3GW is likely to be excessive, particularly but not exclusively in its (lack of) assumed contribution from interconnectors. Political fear of ‘the lights going out’ can easily become a catch-all argument for excessive procurement, and associated subsidy to incumbent generators. The risk of over-procurement, particularly of new conventional capacity on long-term contracts, is that it drives up the costs to consumers; undermines renewable energy by implicitly transferring financial support from renewables to conventional generators; and impedes the European Single Market’s aim at a single pan-Eu electricity market, including by weakening the business case for other options, including future interconnectors that are widely agreed to be increasingly important as the share of intermittent electricity rises.
125 David Newbery is Director of the Energy Policy Research Group (EPRG) at Cambridge University, Research Fellow at Imperial College London, and a Member of the Panel of Technical Experts for DECC on National Grid’s Electricity Capacity Report. Newbery gratefully acknowledges all the input he received the other panel members, A Bankovskis, G Doyle and G Strbac and the DECC team, without implicating any of them in any views expressed here. 126 Michael Grubb is Professor of International Energy and Climate Policy at University College London, and Senior Advisor on Sustainable Energy Policy at Ofgem. Both contributors are writing in their academic capacities and our paper draws only on published evidence.
Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Written evidence (REI0026)
433
UK electricity demand has been on a declining trend for several years. As the New Balancing Services have served to remind us, the decline in capacity margins has been driven in large part by thermal plant retirement due to uneconomic conditions; much of this physical capacity (particularly gas and oil) remains potentially available given modest incentives. In addition, there is large capacity of industrial backup generation, mostly diesel – the only estimate we found was an estimate of 20GW, a huge volume which if correct, and made available at times of peak need, would negate any significant risk of capacity shortfall; the apparent lack of any official estimate of this capacity appears to be an important lacunae which should be corrected as a priority. We also note an indicative lesson from international experience; the US PJM capacity mechanism procured 4.8 GW of new generation, 11.8 GW of demand response, and 6.9 GW of increased net imports (all data cited in Newbery and Grubb, note 11). One fundamental point is confusion of terms: the traditional measure of ‘loss of load’ risks is increasingly divorced from any risk of the ‘lights going out’. It is an estimate of the probability that demand, under normal market operating conditions, exceeds domestic ‘derated’ generating capacity of plant connected and licenced to generate on the system. It is a statistical measure of (mostly existing) contractual relationships; it is only weakly related to the potential resilience of the physical system. This is because it takes no account of mothballed generation or industrial backup (which appear as demand-side management, if companies use it to cut their load on the grid), other forms of demand-side management, or use of interconnectors – which collectively can be termed ‘latent capacity’. Nor does it allow for the various ‘emergency’ measures could be invoked in times of system stress. The ‘Loss of load probability’ is also set on the basis of security standard which in terms of the estimated Value of Lost Load (VoLL) is likely to be excessive from a purely economic standpoint, as we explain in our paper, because it reflects estimates of domestic VoLL but is then applied in practice to industrial VoLL. Thus there is no ‘cliff edge’ at which the lights go out, but rather an increasing array of options for managing tight conditions. These options include the regional pooling of capacity implied by interconnectors, which should be recognised through a more appropriate treatment of interconnectors in security assessments, and/or their participation in the Capacity Mechanism. As with other commodities (including food and gas) international trade supplements domestic production capacity, and security is not synonymous with self-sufficiency. In our paper we delve in some detail into the statistics and modelling assessments, all of which point to the fact that in any credible probabilistic assessment (which is what the ‘Capacity Margin’ concern is ultimately about), interconnectors make a positive contribution. The relevant issue is the risk of interconnectors being unable to supply when needed (most likely due to shortages abroad at precisely the same moment as the UK); excepting the Irish interconnectors, we question whether the probability of this is any higher than non-availability of conventional domestic generation.
Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Written evidence (REI0026)
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Indeed all three key institutions responsible – DECC, National Grid, and Ofgem – have made numerous statements that interconnectors make a clearly positive contribution to the resilience of UK electricity. This should be appropriately reflected in the methodologies of official security assessments, which is not yet the case. For the present, having not taken account of the contribution of interconnectors in the basic assessment of margins for this December’s Capacity Auction, the overall capacity procured in the first auction should be adjusted to reflect the likely future contribution of interconnectors. To conclude, our paper argues that there is considerable ‘latent capacity’ in the electricity system, including but by no means confined to interconnectors, which could be brought into play in the next few years and thus help to maintain security in the face of uncertain trends in electricity demand. Given this, the potential costs of the (probably excessive) caution implied by the decision to procure 53.3GW for 2018-19 could be substantially mitigated by deferring a much greater proportion of this to subsequent, shorter-term auctions. Consequently we consider it would be prudent to reduce the capacity proposed for procurement in the December 2014 auction, and leave more space for contributions that can be procured from a wider range of options once we have experienced national Grid’s management of the coming tight winter conditions, and once DECC has agreed the role of interconnectors in the Capacity Mechanism - all without detriment to the generating resilience of the UK system. Beyond 2020 For the medium term (to 2030), we believe that a great deal may be learned about the options for ensuring continued generating resilience of the UK electricity system. The more active participation of demand side, mediated with ‘smart meters’, and a more systematic integration of industrial and local back-up capacities may extend. Moreoever there is large scope for greater interconnection, including to more diverse regions (such as Scandinavia), contractual and institutional development in Europe, and the advent of electric vehicles which could be connected (or their batteries later utilised) to provide some degree of short-term storage capacity. All these offer potential longer term efficient resources for enhancing system resilience. The Lord’s Enquiry addresses a crucial topic, and we trust that it will take full note of the way that the UK electricity system is changing and could evolve further – and the extent to which this can introduce new options for ensuring the continued generating resilience of the UK electricity system. Reference Newbery, D. and M Grubb (2014) “The Final Hurdle? Security of supply, the Capacity Mechanism and the role of interconnectors” EPRG Working paper (in press) at http://www.eprg.group.cam.ac.uk/research/publications-and-information/eprg-working-papers/eprg-working-papers-2014/ 19 September 2014
Professor David Newbery, Cambridge University, Professor Michael Grubb, University College London and the UK Energy Research Centre (UKERC) – Oral evidence (QQ 69-79)
435
Professor David Newbery, Cambridge University, Professor Michael Grubb, University College London and the UK Energy Research Centre (UKERC) – Oral evidence (QQ 69-79) Transcript to be found under the UK Energy Research Centre (UKERC)
Northern Powergrid – Written evidence (REI0059)
436
Northern Powergrid – Written evidence (REI0059) Case Study "J Marr Group interests include a growing cold store and logistics business and being Europe’s largest supplier of ice products. One of the company’s main sites is based in Northern Powergrid’s Yorkshire region, where they consume over 15 GWh of electricity per annum. The site has been involved in demand response initiatives since 2007, including winter peak cost avoidance and the provision of services to National Grid. This flexibility is achieved primarily by managing cold store temperatures and procedures, so that the thermal inertia in the building can maintain appropriate operating conditions. The site also tailors shift and production patterns in response to longer term signals from electricity charges. As the response available from the site is below the capacity thresholds set by National Grid, the Group uses Energy Services Partnership, part of Ameresco Inc., as an aggregator to market their capability to potential users. Across all the demand response initiatives the J Marr Group has been involved in, they estimate they have generated benefits of nearly £240k since 2012, either through increased revenue or cost avoidance. J Marr’s main site took part in industrial-scale demand side response trials run by Northern Powergrid in 2012 and 2014 as part of its Customer-Led Network Revolution project. It was able to successfully provide 0.6 MW of response to reduce demand in the network’s peak congestion period in the evening. This project was one of the UK’s largest smart grid projects looking at how distribution network operators can most efficiently facilitate the transition to a low carbon future. A key aspect related to the use of demand side response to address localised network constraints arising from the projected increase in low carbon technologies connected to the network. The J Marr site was already familiar with the need to respond to external signals from third parties through their experience in National Grid’s STOR programme and had minute by minute metering in place. Looking forward, the J Marr Group expects it will continue to profit from the flexibility it has developed." 6 February 2015
Nuclear Industry Association (NIA) – Written evidence (REI0020)
437
Nuclear Industry Association (NIA) – Written evidence (REI0020)
1. The Nuclear Industry Association (NIA) welcomes this opportunity to respond to the Select Committee’s Call for Evidence.
2. NIA is the trade association and information and representative body for the civil
nuclear industry in the UK. It represents around 270 companies operating in all aspects of the nuclear fuel cycle, including the current and prospective operators of the nuclear power stations, the international designers and vendors of nuclear power stations, and those engaged in decommissioning, waste management and nuclear liabilities management. Members also include nuclear equipment suppliers, engineering and construction firms, nuclear research organisations, and legal, financial and consultancy companies.
Overview
3. As the trade association for the nuclear industry the NIA is not in a position to offer detailed comments on the current and future resilience of the UK’s broader electricity infrastructure; this is more a matter for energy analysts, National Grid, and the utilities.
4. We would however note that so far as generation is concerned it is generally accepted that a combination of market and wider policy developments – such as European legislation affecting combustion plant and incentives for growth in non-dispatchable renewables– are potentially reducing the sector’s resilience. This process will be exacerbated over the next fifteen years as all but one of our existing nuclear power stations are scheduled to close over this period.
5. Against this background large scale investment will be needed over the coming decades in the generation sector. If the UK’s carbon reduction and security of supply objectives are to be met, this will need to include major investment in low carbon generation – new nuclear and renewables, and potentially coal with CCS - as a matter of urgency. As the Committee notes, the Government has put in place policy measures to encourage this investment, including last year’s Energy Act. We fully support these measures.
Role of nuclear in supporting the resilience of the UK’s electricity infrastructure
6. The UK has a long history of achievement in nuclear power since commissioning the world’s first nuclear power station in 1956. We now have a world class industry spanning the whole fuel cycle, and a track record in design and construction. Importantly we also have an exemplary safety record, with no serious incidents in over 50 years of commercial operation.
7. Throughout this time the nuclear fleet has provided important security of supply
benefits. In the Department of Energy and Climate Change’s 2012 Energy Security
Nuclear Industry Association (NIA) – Written evidence (REI0020)
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Strategy, four elements of security of supply were considered: adequate capacity; diversity; reliability and demand-side responsiveness. Nuclear power stations can help deliver against the first three of these.
8. In particular nuclear power stations contribute to the resilience of the UK’s energy system by helping to ensure a diverse mix of technology and fuel sources. Investment in new nuclear power stations will reduce exposure to the risks of supply interruptions and of sudden and large spikes in electricity prices that can arise when a single technology or fuel dominates electricity generation.
9. Moreover global experience shows that modern nuclear stations operate reliably, and their operational and refuelling characteristics mean that they can continue to generate electricity at or close to maximum output for extended periods. For most light water reactors, refuelling is only required once every 12 – 18 months. Conversely gas-fired power stations would have to shut down almost immediately if their fuel supplies were interrupted, and the UK increasingly relies on imports of coal for the remaining coal-fired power stations.
10. Finally, in relation to fuel supplies, there is sufficient uranium available to fuel the UK’s current and future nuclear plant for many years to come. Moreover because the price of uranium is not directly correlated to global oil and gas prices, and because the fuel and operating costs are a low proportion of the overall costs, nuclear generation is relatively unaffected by uranium price fluctuations. If global demand significantly affected the price of uranium, it would only have a limited effect on the cost of generation.
Need for System Resilience
11. The UK enjoys one of the most robust and resilient electricity systems in the world. This is of course vital for a flourishing economy, and is also of importance for nuclear power operators. As nuclear stations operate continuously, it is important that the high voltage network is available for exports of electricity from the site. Nuclear stations also require secure electrical supplies on site in the event of breakdowns and during periods of maintenance. Although the safety of the plant is assured through the provision of on-site stand-by generation, the security of external supplies to the site is also important for the safety case.
Flexible Nuclear Generation
12. Nuclear stations with their low variable costs, high availability and low carbon emissions are best suited to meet baseload demand, and this is how they have been operated, and are planned to operate, in the UK. However whilst this is the most economic course modern plant can be designed to be capable of load following and in France, which has a very large proportion of nuclear power on the system with hydro-electric power providing some flexibility to respond to changing demand, a number of the operating PWRs are able to change their output quickly at the request of the system operator.
Nuclear Industry Association (NIA) – Written evidence (REI0020)
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13. If the UK nuclear fleet were ultimately to make up a much bigger proportion of total
generation it would be technically possible to provide nuclear plant capable of load-following too, although this would not be the optimum from an economic perspective.
What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
14. As noted above the NIA supports the Government’s electricity market reform proposals. We believe these reforms, that have strong cross party support, will provide investors with the certainty they need to proceed with the construction of new low carbon plant.
15. Against this background the UK is seeing a substantial commitment to new nuclear build, with EDF Energy in the final stages of work towards an investment decision on the first of two new projects at the end of the year; Horizon Nuclear Power entering the third stage of the Generic Design Assessment process for their proposed new build at Wylfa; and NuGeneration Ltd taking forward plans for new plant at Moorside in Cumbria. Together these consortia have plans for around 16 GW of new nuclear capacity in the period to around 2030.
16. However significant funds will be needed to bring these plans to fruition, and these will not be forthcoming without ongoing investment confidence that robust, long term, transparent, secure and Government backed arrangements are in place. It is therefore vital that Government continues to make good progress on implementing the detailed provisions in the Energy Act 2013 and thus complete the Electricity Market Reforms without delay.
19 September 2014
Professor William Nuttall, Open University, Professor Jon Gibbins, University of Edinburgh and Dr Keith MacLean, University of Exeter – Oral evidence (QQ 91-101)
440
Professor William Nuttall, Open University, Professor Jon Gibbins, University of Edinburgh and Dr Keith MacLean, University of Exeter – Oral evidence (QQ 91-101) Transcript to be found under Professor Jon Gibbins
Ofgem – Written evidence (REI0044)
441
Ofgem – Written evidence (REI0044) Overview of Ofgem The Office of Gas and Electricity Markets is a non-ministerial government department. It has been designated as the independent National Regulatory Authority in Great Britain for the purposes of certain European Union Directives (the “Third Package”) and as a National Competition Authority with concurrent jurisdiction in respect of the energy sector. Our aim is to make a positive difference for energy consumers. Our principal objective is to protect the interests of existing and future electricity and gas consumers in Great Britain. The interests of such consumers are their interests taken as a whole, including their interests in the reduction of greenhouse gases and in the security of the supply of gas and electricity to them. Ofgem is generally required to carry out its functions in the manner it considers best calculated to further the principle objective, wherever appropriate by promoting effective competition. An important element in fulfilling our duty is to understand what really matters to consumers and to ensure they remain at the heart of everything we do. Call for evidence We are pleased to respond to the House of Lords Science and Technology Select Committee’s call for evidence for an inquiry into ‘Resilience of Electricity Infrastructure.’ The Committee describes resilience in the context of whether there will be enough electricity to meet demand in the short term, and whether current policies will be effective in ‘keeping the lights on’ through to 2030. This includes how the system will handle sudden, unexpected events such as severe weather, power station failure or a potential cyber-attack. The ‘system’ includes electricity generation, transmission and distribution infrastructure. The call for evidence considers resilience in a framework of energy security, affordability and decarbonisation. We have considered this ‘energy trilemma’ when responding to each question below. Our approach to resilience and role in security of supply A resilient system needs to have enough generation capacity to meet demand at all times, sufficient transmission and distribution networks to ensure supply where customers need it, and adequate market and system operation arrangements to balance the system in the present and future.
Ofgem – Written evidence (REI0044)
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We monitor the market to assess security of supply and identify potential risks. Where we have identified concerns we have taken action where appropriate127; and we coordinate with the Department for Energy and Climate Change (DECC) and National Grid128 to address any security of supply issues. DECC is responsible for setting overall policy on energy security, such as setting the relevant policy objectives, legislative framework and security of supply standards. We are responsible for regulating the market129, and the regulatory price control settlement for networks consistent with these objectives and standards. In the wider context, Great Britain (GB) is linked to continental electricity markets via interconnectors. We have recently rolled out the developer-led ‘cap and floor’ regulatory regime to near-term interconnector projects to facilitate timely investment. We also work within Europe to develop and implement European legislation to complete the internal energy market. The two primary components of electricity infrastructure are the generators (and interconnectors) that produce electricity, and the networks that deliver it to consumers. The resilience of these components can be assessed independently but it is better to consider resilience across the system as a whole. For generators that produce electricity, we rely on ‘market’ solutions to ensure that supply (i.e. generation capacity) meets demand. For networks, we use regulatory mechanisms in relation to onshore networks to ensure that there is sufficient network capacity for electricity to be delivered reliably to consumers. We provide requirements by which the network is maintained and operated to deliver system resilience, and ensure that these requirements evolve in line with changing nature of the electricity system. We also ensure that the market operations of the network, such as the way in which users are charged for using the network, provide signals that support the efficient development of the network. Interconnectors play an important role in a resilient GB network as, in times of system stress, electricity can be imported from other markets. There are plans for a significant increase in new interconnection and this will help support future security of supply. We have developed a regulatory regime for new electricity interconnectors that will help to ensure that efficient levels of investment are brought forward in a timely way. In future, we see flexible demand becoming a third important component that will impact overall system resilience. The demand side has historically been essentially static and relatively predictable. Going forward however, we can see that consumers could become an active part of the overall supply chain, potentially modifying their consumption in response to market signals. This will add further complexity to the market and regulatory arrangements but could deliver material benefits in terms of overall system efficiency and reduced cost.
127For example, having identified concerns in Project Discovery with the calculation of cash-out prices and how they may undermine balancing efficiency and security of supply we launched the Electricity Balancing Significant Code Review reforms. 128 National Grid Electricity Transmission plc (NGET) is the electricity system operator (SO) for Great Britain (GB). As SO, NGET plays an important role in the functioning of the GB electricity market. It is responsible for balancing the electricity system by ensuring that generation on the national electricity grid matches demand on a second by second basis. To do this, NGET buys and sells energy and procures associated balancing services. 129 For example, by putting in place and (where appropriate) enforcing licence conditions, including those that govern the operation of the networks.
Ofgem – Written evidence (REI0044)
443
Resilience in Markets The next two winters are expected to be increasingly tight for electricity due to a significant reduction in electricity supplies from coal and oil generation plant in recent years, coupled with limited investment in new plant. However, Ofgem, National Grid and DECC are all working to avoid disruptions to consumers. Ofgem plays a leading role in the current debate about resilience. In 2009 we published Project Discovery130, a comprehensive review of Britain’s energy supplies. This brought to light challenges to the resilience of the UK energy system such as the impacts of replacing older coal and oil power stations under EU environmental legislation, as well as changes to the generation mix over the next decade. As a result of this Project, we now report our assessment of electricity capacity to DECC each year in the Electricity Capacity Assessment Report. Our 2014 Electricity Capacity Assessment (CA 2014)131 is based on data from National Grid accompanied by our own analysis. It suggests that, without new measures being introduced, the risks to the security of our electricity supply associated with the level of generation capacity in the system would increase up to 2015/16. Capacity margins132 would be expected to fall over the next two winters as older power stations close, before showing an improvement in the later years of our analysis. The Government’s response to the reducing generation capacity margin is Electricity Market Reform (EMR). This has been designed by DECC and aims to increase resilience by decreasing the risks to security of supply, while incentivising low carbon generation. Ofgem has an enduring role in this scheme both as the regulator of National Grid, who are administering the policies, and, in future, as owner of the rulebook for the Capacity Market, which governs the technical aspects of the policy. The first delivery year for the EMR capacity market is 2018-19. In order to reduce the risk of customer disconnections in the short term we approved new tools in 2013, the New Balancing Services (NBS)133. These are tools that National Grid can use to help balance the electricity system and manage lower margins. The use of the NBS means that the likelihood of disconnections for consumers in the coming two winters has reverted to the levels seen in recent years. Ofgem also launched the Electricity Balancing Significant Code Review (EBSCR) in response to concerns identified in Project Discovery. Ofgem completed its review in May and published its conclusions and recommendations for reform. A key aim of the reforms is to ensure that price signals appropriately reflect electricity scarcity, and more accurately capture the value of flexible energy sources (e.g. demand side response and electricity storage). This will
130 https://www.ofgem.gov.uk/ofgem-publications/76124/discoveryfs.pdf 131 https://www.ofgem.gov.uk/electricity/wholesale-market/electricity-security-supply 132 Capacity margin is the average level of supply over demand during winter. 133 These New Balances Services mean that National Grid can carry out tenders for businesses which are willing to reduce electricity use during times of high demand, in exchange for a payment. National Grid can also tender for new contracts with power stations so they can provide extra reserve if needed, in exchange for a payment.
Ofgem – Written evidence (REI0044)
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promote efficient investment in such sources, and increase overall market resilience. Industry is now conducting a process to modify the industry codes based on our conclusions. Once complete the proposed modifications must be approved by us for them to come into effect. On the demand side, Ofgem is committed to establishing regulatory and commercial arrangements that support efficient system-wide demand-side response (DSR)134. DSR could play an increasingly important role in supporting the improvement of the resilience of the UK electricity system until 2020 and beyond. This is because DSR has the potential to reduce demand at times of system stress; for example during peak winter periods or when unexpected events happen, such as the sudden loss of generation. DSR could also contribute to our sustainability goals by reducing the need for new investment in generation and network capacity provided this is properly balanced against overall security of supply requirements. Our Smarter Markets Programme135 sets out four priority areas of reform in order to fully support the aims for DSR. To support the resilience of the GB electricity sector it is important that parties136 work together to establish more efficient, dynamic and innovative energy markets. To do so, they need to understand the value of using flexible measures to become more efficient in the way they operate in the market and use the electricity system. We also need to ensure that networks develop in a way that supports changes in the energy markets. Resilience in Networks In this period of change to the energy sector, onshore network companies need to be more innovative, think longer-term and engage actively with customers and others with an interest. We have developed a new regulatory regime, in part to address this. In contrast to the supply and demand sides of the electricity supply chain which are market driven, we directly regulate the network companies, which are either national or regional monopoly companies. In 2010 we introduced our RIIO approach (Revenue = Incentives + Innovation + Outputs)137. This retains the best elements of the mechanisms used previously which have a strong record in driving efficiency, but also holds the network companies to account for delivering customer focused outputs in exchange for the revenue framework allowed. It also encourages innovation and a longer term focus in order to deliver sustained efficiencies and higher quality service. This includes new challenges, for example, from new technology generation. The electricity transmission companies are already operating under RIIO arrangements and we are close to finalising the price control process for the electricity distribution companies; their first RIIO control period will commence in April 2015. As well as the price control 134 https://www.ofgem.gov.uk/electricity/retail-market/market-review-and-reform/smarter-markets-programme/demand-side-response 135 https://www.ofgem.gov.uk/electricity/retail-market/market-review-and-reform/smarter-markets-programme 136 In this context, ‘parties’ are those being suppliers, aggregators, Distribution Network Operators, Transmission Operators or the System Operator, National Grid. 137 https://www.ofgem.gov.uk/network-regulation-per centE2per cent80per cent93-riio-model
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mechanisms, there are commercial arrangements governing the networks. These are set out in the licences of the network companies, and in a series of industry codes to which all relevant industry participants are parties including generators and suppliers. Part of the purpose of these arrangements is to ensure appropriate signals are sent to users of the system about, for example, where to locate new generation taking into account the impact they have on the network. This supports development of an economically efficient, resilient network where investment is planned and delivered in a timely manner to meet changing patterns of generation and demand. The network companies are also required to meet a number of technical standards (as set out by government) that help ensure network resilience. These arrangements have not been changed with the introduction of RIIO. However, they evolve on an ongoing basis in response to the changing nature of the system. For example, the rules governing the level of investment required to deliver the agreed levels of system security on the transmission network were changed in 2011 to reflect the increasing amount of renewables on the system. We recognise that the demands on the networks are changing significantly and we cannot assume that existing approaches to network design, development and operation will be fit for purpose in the future. We have therefore placed significant emphasis on the need for innovation. This was reflected in 2005 with our Innovation Funding Incentive and Registered Power Zones. In 2010 we introduced the Low Carbon Networks (LCN) Fund and RIIO has network innovation incentives embedded in its structure. These incentives are intended to both support research and development innovation, and encourage the electricity network companies to think about different ways of delivering throughout their business plans. In addition, we work with DECC through two stakeholder forums. To address transmission issues including guidance on likely future investment, we have the Electricity Networks Strategy Group and to address the new challenges and opportunities for distribution we set up the Smart Grids Forum in 2011. We have played a leading role in work on smart grids and future distribution networks that have been taken forward by the network companies. Network resilience is an important aspect of this work. As a representative at the national Energy Emergency Executive Committee (E3C), alongside DECC and energy industry participants, Ofgem has led and contributed to the development of the assessment of energy network resilience issues and measures to mitigate these. This has included work on the assessment of cyber security risks, and network resilience to flooding and other severe weather events. Our role in affordability One of the greatest challenges in terms of affordability is that in recent years, average bills have increased at a rate higher than inflation. This has been due to higher wholesale costs, transmission and distribution charges (though these are now broadly flat going forwards), and government social and environmental levies. This affects all energy consumers, from the smallest to the largest, domestic and business. Our primary contribution to affordability of the energy market is driving competition and regulating network company revenues to ensure prices are no higher than they need to be.
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In addition, Ofgem E-Serve delivers government schemes to help consumers reduce household bills and cut carbon emissions. In protecting energy consumers, Ofgem pays particular regard to those who might be in vulnerable situations138. Ofgem’s Consumer Vulnerability Strategy details Ofgem’s work in this area139. Reform of the Retail Market In 2010, we launched the Retail Market Review (RMR) to respond to concerns that the energy market was not working effectively for consumers. Since then, we have implemented a number of reforms to make the retail energy market simpler, clearer and fairer for consumers so that they are able to engage in the competitive market. Competitive markets result in greater pressure on prices which is the best way to deliver lower costs in the retail and wholesale markets. In addition, a range of key projects for 2013-2014 are focused on providing simpler choices for consumers, with clearer information about products, prices and available savings, as well as fairer treatment in all supplier interactions with their customers. We will continue to monitor both the retail and wholesale markets. We have worked with the Office of Fair Trading and the Competition and Markets Authority (CMA) to carry out the first review of competition in the GB energy market. This found that competition was not working as well as it should for consumers and led us to make a market investigation reference to the CMA. Incentivising Network Companies As well as providing resilient infrastructure, our regulation of the electricity transmission and distribution network companies sets revenue controls and provides obligations and incentives on the energy companies140. The new RIIO approach for network price controls encourages network companies to take responsibility for developing and justifying a long-term strategy for delivering the network services that their customers value on a sustainable and efficient basis. We previously estimated that at least £32 billion of investment in networks might be needed over the next decade141. However, recent experience has shown that this figure may be significantly exceeded in the future. This investment will be recovered through transmission and distribution charges, and will ultimately rest with customers. Arrangements that ensure investment is planned and delivered efficiently is therefore an important part of the RIIO
138 A vulnerable customer is defined as one who is significantly less able than the typical consumer to protect or represent their own interests, and or is significantly more likely to experience detriment, or for that detriment to be more substantial. 139 https://www.ofgem.gov.uk/about-us/how-we-work/working-consumers/protecting-vulnerable-consumers 140 We have just set RIIO-T1 for electricity transmission companies from April 2013-March 2021 and our RIIO-ED1 for electricity distribution companies is due to run from April 2015–March 2023. Our RIIO-T1 control was the first regulatory control under our new RIIO approach and applies to transmission owners. Details are available on our website at https://www.ofgem.gov.uk/network-regulation-%E2%80%93-riio-model/riio-t1-price-control. 141 Through Project Discovery in 2009.
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approach to delivering long term affordability for customers while ensuring security of supply. We have an active role in approving major transmission investment links such as the Caithness Moray link in the North of Scotland which requires an investment of over £1.3 billion. Under RIIO, companies are encouraged to deliver efficiencies through coordination on network planning. Examples of this include planning of outages to allow investment to take place on transmission assets, thereby minimising the costs of additional balancing actions required for the SO to manage the periods that part of the network is unavailable. The market and commercial arrangements also support the efficient planning of network by, for example, signalling where new investment may be required to accommodate new generation on the network. Our draft proposals under our Integrated Transmission Planning Regulation project (ITPR) put forward options for enhancing the coordination of system planning for the onshore and offshore networks. The system must also be operated efficiently. To do this we have developed System Operator (SO) incentive schemes142 that are designed to encourage National Grid, as the SO for GB, to operate the electricity transmission system in an efficient and economic manner. This includes the services that the SO procures to ensure the resilience of the system. Our work related to decarbonisation Our principal objective is to look after the interests of consumers; this includes reducing greenhouse gas emissions and contributing to the achievement of sustainable development while taking note of government guidance on social and environmental matters. The electricity sector is undergoing significant change as part of the transition to a low-carbon and energy companies have a vital role in facilitating this. EU and UK targets for curbing greenhouse gas emissions and increasing renewable energy provide the overall policy direction for decarbonising the energy sector and must consider renewable intermittency in the context of resilience. DSR, referred to previously, could play an increasingly important role in supporting this policy objective. It has the potential to reduce bills for consumers, enhance security of supply and contribute to sustainable development. Over the coming year, we will continue to develop our Smarter Markets Programme and our approach to smart grids. Ofgem is committed to encouraging all customers to consume energy more efficiently, both in terms of how much they consume and when. Ofgem’s response to specific questions in the call for evidence Below we respond directly to questions that the Committee laid out in its call for evidence that are most relevant and appropriate for Ofgem.
142 https://www.ofgem.gov.uk/publications-and-updates/national-gridper centE2per cent80per cent99s-proposed-new-balancing-services-decision-letter
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1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base?
Resilience in markets The GB electricity system has historically delivered high levels of security of supply. Our CA 2014143 shows that capacity margins are expected to reduce over the next two winters as older power stations close, before improving after the middle of the decade. However, the probability of consumer disconnections has reduced significantly due to measures taken by Ofgem, National Grid and Government (see Q2). We are confident that National Grid has the right levers to keep the lights on. Our CA 2014144 analysis sets out our view of the risks to security of supply over a five year period. We base our analysis on the first four years of National Grid’s Future Energy Scenarios (FES)145. Even within this short timeframe, there is a high level of uncertainty around the supply and demand outlook, as illustrated by the significant difference between National Grid’s estimate and the actual demand levels in 2013146. We have captured uncertainty through sensitivity analysis around National Grid’s scenarios (pessimistic and optimistic sensitivities147). We use de-rated capacity margins, the average excess of available generation over peak demand, to illustrate trends in the market, but this measure has limitations. We therefore also present the Loss of Load Expectation (LOLE). LOLE is the average number of hours in a year where we expect that National Grid, as the SO, may need to take action that goes beyond normal market operations (e.g. voltage reduction). This is a probabilistic measure widely used as it captures the impact of intermittent generation and instances of extreme demand and/or low supply. As part of the EMR Capacity Market, DECC introduced a Reliability Standard of 3 hours LOLE. On the pessimistic sensitivity of the report, the range of LOLE is projected to increase to a maximum of around 9 hours in 2015/16, before it drops to a maximum of around 3 hours for the last three winters of the analysis. On the optimistic sensitivity the LOLE remains at approximately zero hours for the entire period. Figure 1: Loss of Load expectation for the upcoming winters (taken from CA 2014)
143 For more information see: https://www.ofgem.gov.uk/ofgem-publications/88523/electricitycapacityassessment2014-fullreportfinalforpublication.pdf 144 All Electricity Capacity Assessment documents can be accessed here: https://www.ofgem.gov.uk/electricity/wholesale-market/electricity-security-supply 145 National Grid’s Future Energy Scenarios report can be found here: www.nationalgrid.com/fes. 146 Average Cold Spell (ACS) demand for winter 2013/2014 was 54.1GW which is approximately 3% lower than National Grid forecast in the Future Energy Scenarios 2012. National Grid assesses that ACS peak demand dropped by around 1.5GW last winter, compared to winter 2012/13. Despite the expansion of the GB economy, demand unexpectedly fell across all three sectors, i.e. industrial, commercial and residential. National Grid estimates that approximately half of this drop was due to a reduction in energy consumption. 147 Sensitivities illustrate only changes in one variable (e.g. demand) at a time and do not capture potential mitigating effects, for example the supply side reacting to higher demand projections.
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The methodology for the Electricity Capacity Assessment provides the underpinning evidence base for our security of supply analysis and has been continuously reviewed and consulted on from the outset of its development. We have held workshops and consulted with industry in each of the three years we have produced the report. Similar methodologies have been adopted in other markets including many EU countries. Resilience in networks Reliability is an important measure of resilience for all networks. While difficult to compare, a recent Council for European Energy Regulators (CEER) report148 shows that the UK’s is one of the best performing electricity networks in Europe. Caution should be used in making such comparisons given the differences between networks but this provides some useful evidence. The balance between greater reliability and cost in a regulatory control is informed by understanding consumers’ priorities and willingness to pay. RIIO provides us with a robust framework in which to carry out this work and for consumers, other network users and stakeholders to feed in to this. We will also consider future consumers’ needs including through a measure of network asset health that help indicate if cost reductions were achieved at the expense of sustained reliability. For safety reasons electricity transmission networks are engineered to a high standard of reliability. Electricity transmission owners have networks that are engineered to a high standard so that they are generally available more than 99 per cent of the time. Transmission owners face a reliability ‘energy not supplied’ financial incentive as part of their RIIO-T1 outputs.
148 The most recent CEER Benchmarking Report on the Continuity of Electricity Supply (v5.1) is available here: http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Electricity/Tab3/C13-EQS-57-03_BR5.1_19-Dec-2013_updated-Feb-2014.pdf.
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The first 20 years of incentive regulation for electricity distribution networks has seen around a 30 per cent reduction in the number and duration of interruptions. The significant improvements in electricity distribution network performance are shown in Figure 2 and 3 below. Figure 2: Number of customer interruptions (CIs) with and without exceptional events
Figure 3: Customer minutes lost (with and without exceptional events)
Customer
interruptions
per 100
customers
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2. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’?
Government sets overall policy on energy security in GB and National Grid, as operator of GB electricity system, has responsibility for balancing the system on a second-by-second basis each day. Ofgem is responsible for regulating the market; monitoring security of supply plays a central role in fulfilling our objective of protecting the interests of present and future consumers. We work together with the Government, National Grid and industry to address any issues identified and a series of interventions and reforms to market arrangements, including the EMR and NBS, have been recently introduced to improve resilience in the next decade. Our CA 2014 indicates that the measures that are in place or being put in place to improve the resilience of GB’s electricity system until 2020 are significantly reducing the probability of customer disconnections (to within the Government’s reliability standard) and are helping to keep the lights on. Our new RIIO approach to regulation encourages network companies to think more strategically and long-term about delivery. This is achieved by rewarding companies that are more innovative and customer-focused. Electricity Market Reform EMR is being introduced by DECC and aims to increase resilience by ensuring electricity security of supply and meeting decarbonisation objectives at best value for consumers. We are supportive of these aims and the value that EMR can deliver for consumers. To meet decarbonisation objectives DECC are introducing Contracts for Difference for low carbon generators. These will guarantee a fixed price for electricity, de-risking the investment in these forms of generation. As part of EMR, DECC are introducing a Capacity Market, which pays traditional forms of generation for their capacity in return for a guarantee that they will be delivering electricity when the system needs it. DECC have designed the capacity market to ensure there is adequate capacity but not to deal with flexibility issues or transmission or distribution faults. Our own EBSCR is important in incentivising flexible capacity. System Operator Incentives The SO, National Grid, is responsible for balancing the electricity system by ensuring that generation on the national electricity grid matches demand on a second by second basis. To do this, National Grid buys and sells energy and procures associated balancing services. It also provides valuable information to market participants such as forecasts of wind generation. Ofgem regulates the actions of the SO to ensure that it is encouraged to minimise the costs of balancing the system for market participants and to ensure that this is achieved
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efficiently. Statutory obligations on National Grid include keeping the system secure and operating the system in an economic, efficient and coordinated manner. We have historically ensured that this is achieved by financial and reputational incentives.149 This will ultimately improve resilience of the electricity system to 2020 and reduce the cost that consumers face from the SO’s actions. New Balancing Services As referenced in your call for evidence, Ofgem has taken decisive action by approving additional tools for National Grid to continue to balance the system in the event of lower electricity margins from this winter, when there will be less generation available. National Grid can carry out additional tenders for businesses which are willing to reduce electricity use during times of high demand, in exchange for a payment. This is a common way of managing supply and demand on electricity grids and historically businesses in GB have provided balancing services to National Grid on a commercial basis. National Grid can also tender for new contracts with power stations so they can provide extra reserve power when needed. In July 2014, National Grid launched the tender for a pilot of this demand-side service for a volume of up to 330MW. In September, National Grid announced a new tender for the supply-based service as a precautionary measure to help manage the uncertainty for winter 2014/15 due to recent market developments.150 This tender will close on 30 September 2014. Without the NBS, National Grid’s FES analysis suggests that customer disconnections would be expected to occur between once every 8 years (1 in 8 years) and once every four years (1 in 4 years) in 2015/16. However, if National Grid procured the maximum volume of new balancing services it has indicated for 2015/16, the additional measures would reduce the risk of disconnections up to between around 1 in 73 years and 1 in 31 years, which is well within the government’s reliability standard and within the range of risks forecasted ahead of recent winters. Electricity Balancing Significant Code Review Ofgem has also directed National Grid to launch two modification proposals to the Balancing and Settlement Code151 aimed at giving effect our final conclusions on the EBSCR. The EBSCR reforms will ensure the balancing arrangements (and imbalance pricing) better serve the principle of cost reflectivity, representing costs comprehensively, and at the margin152. This
149 For more information: https://www.ofgem.gov.uk/publications-and-updates/electricity-system-operator-incentives-incentives-2015 150 National Grid’s announcements about additional safeguards against an uncertain security of supply outlook during the mid-decade period can be found on http://www.nationalgrid.com/uk/electricity/additionalmeasures 151 Ofgem’s directions can be found here: https://www.ofgem.gov.uk/publications-and-updates/direction-national-grid-electricity-transmission-plc-relation-electricity-balancing-significant-code-review 152 Pricing at the margin means market parties internalise the additional cost the System Operator incurs to balance the system as a result of the failure by the market to provide one extra unit of ‘balance’ – and thereby supports efficiency.
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should drive market participants to respond to issues such as scarcity and technological change in a way that supports efficiency, effective competition and innovation, and ultimately delivers benefit to the consumer. The bulk of the EBSCR reforms (sharpening the prices that generators and suppliers face for failing to balance supply with demand), are scheduled for introduction in advance of winter 15/16. The proposals are now proceeding through an industry led code modification process and will need to be approved by us before they can come into effect. System Operator Innovation Roll-Out Mechanism In addition, Ofgem incentivises the roll-out of innovation from National Grid through the System Operator Innovation Roll-Out Mechanism (SO-IRM). This was designed to provide the SO with an opportunity to roll-out proven innovations that will provide enduring benefits to consumers and would be uneconomic for the SO to roll-out during the current two year incentive scheme. The SO-IRM achieves this by providing up to £10 million of funding for the roll-out of proven technology that the SO can demonstrate will provide resilient, enduring benefits to consumers and would be uneconomic for the SO to roll-out during the current two year incentive scheme. Demand-side Response and Smart Meters The roll-out of smart meters153 will also provide opportunities for parties to use the electricity system more resourcefully thus creating more efficient markets to improve the resilience of the UK electricity system. It will also drive market participants to respond to issues such as scarcity and technological change in a way that supports efficiency, effective competition and innovation, and ultimately delivers benefit to the consumer. The roll-out will be completed after 2020, and efficient energy use will play a key role in this transition in the short-medium term. DSR customers - who respond to a signal to change the amount of energy they consume from the grid at a particular time – could play an increasingly important role in supporting the improvement of the resilience of the UK electricity system until 2020 and beyond. Ofgem is committed to establishing regulatory and commercial arrangements that support efficient system-wide use of DSR; executed through a framework that clearly formalises the interactions between different parties within the existing market model to ensure consumers benefit from providing flexible demand response and that energy companies recognise the value in using DSR. Price Controls and Incentives Between 2008 and 2010 we undertook a fundamental review of how we regulate networks known as RPI-X@20. This recognised the success of our established approach but also that the network faced greater challenges in the coming decades to maintain resilient networks (including carrying out necessary investment) as many assets come to the end of their lives at the same time as new challenges arise e.g. from decarbonising energy. In Project Discover
153 The Government is mandating the rollout of smart meters to all domestic and non-domestic customers by the end of 2020.
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we estimated that at least £32 billion of investment was needed in the networks. Experience from RIIO-T1154, GD1 and ED1 to date, suggest this level of investment will be exceeded. Our network regulation needs to make sure that the revenues allowed are sufficient to support the efficient level of investment while protecting consumers from the impact on bills. Our new RIIO model for network price controls has built on past best practice but recognises the new range of challenges facing network companies such as replacing many existing network assets reaching the end of their useful lives and delivering the changes needed to deliver a low carbon energy sector. RIIO does this by being very clear about outputs to be delivered. These are things consumers care about for example: reliable networks with a minimum of interruptions; timely connections; innovation that will continue to benefit consumers despite changes in the energy sector. In RIIO we expect comprehensive consumer focused outputs. These will be partly informed by what current consumers want but will also take a longer term perspective to include future consumers and wider resilience and sustainability across the energy networks. In some cases we include scope for rewards and penalties with the basis of financial incentives being driven by consumer value, for example through the interruptions incentive scheme155. This has led to significant reductions year-on-year in both the frequency and length of customer interruptions. Within the RIIO settlements, we also include allowances for network companies to carry out a range of activities to improve the resilience of their networks. These include flood mitigation schemes, critical national infrastructure and investment in Black Start batteries156, which would be needed in the event of a UK wide failure of the electricity transmission network. Ofgem also measures network operators’ delivery of their Network Output Measures (NOMs). These cover assessment of the health and criticality of network assets so that network operators can demonstrate they are effectively assessing the risk and the consequences of asset failure, and delivering mitigation measures required to manage this appropriately. There are also conditions in the network operators’ licences which set out their requirements in relation to NOMs. We monitor network companies’ progress in delivering in all of these areas during the price control through our annual regulatory reporting framework. We have reviewed how this should work in light of the RIIO controls and the changes they brought with them including an even greater reliance on stakeholders to help us understand how the network companies are performing.
154 More information on the RIIO model of network regulation and on the RIIO-T1, GD1 and ED1 price controls is available on Ofgem’s website: https://www.ofgem.gov.uk/network-regulation-per centE2per cent80per cent93-riio-model. 155 For more information on the interruptions incentive scheme, please see the Ofgem website: https://www.ofgem.gov.uk/electricity/distribution-networks/network-price-controls/quality-service/quality-service-incentives 156 More information on black start resilience can be found in “ENA Engineering Recommendation G91 Issue 1 2012 – Substation Black Start Resilience”.
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3. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made?
Resilience in markets Through efficient design of the market arrangements, Ofgem seeks to incentivise the market to make efficient decisions that deliver in the consumer interest when assessing the costs and benefits of investments in electricity resilience. The key to an efficient outcome is an alignment of incentives of market parties (such as suppliers and generators) with the interests of the consumer. Notable in this respect are Ofgem’s EBSCR reforms. A key element of these reforms is the introduction of a price for the ‘Value of Loss Load’ (VoLL), the cost borne by the consumer when supply is interrupted. When consumers are disconnected, owing to the failure of parties to balance supply and demand, introduction of VoLL pricing ensures that parties face the cost that their failure to balance imposes upon the consumer. This incentivises the market to deliver resilience, for instance through investment in storage technologies, up to the point where this investment delivers a net benefit to the consumer. Resilience in networks The costs and benefits of investing in network/system resilience are assessed through our price control methodology and incentive regulation. We have developed better approaches and understanding of network companies’ business plans at each price control and have driven significant reductions in networks costs. Since privatisation, through to 2006-07, the networks component of energy bills fell by nearly 45% in real terms. Since 2006-07, through to the current year (2014-15), networks have invested in major asset replacement programmes and realigned the electricity transmission networks for a changing generation market. As a result, network costs have experienced a planned rise of 48% in real terms since 2006-07. Over the eight year period since 2006-07, network costs rose on average by about 5% per annum in real terms, adding about £100 to the typical household dual fuel bill. Costs are still about 17% below levels at the time of privatisation thanks to greatly improved efficiency. Annual electricity distribution operating costs, for example, are £1.75bn lower than they were. There has been some £80 billion of investment in the networks since privatisation; investment which is now running at about £6 billion per annum. As a result, the networks are substantially more reliable and robust than they were. For example, power interruptions experienced by customers are down by 30% since 2002. We anticipate that network costs to consumers will remain broadly stable in real terms through to the end of this decade. RIIO includes a broad toolkit for cost assessment. We made use of a wide range of quantitative and qualitative data available to us in making our assessment of costs and benefits. This included network companies’ written narrative and supporting evidence for their business plans, historical cost and performance data and company forecasts. For each of the networks subject to the RIIO price control, we carried out comparative benchmarking
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at both an industry level and at a more detailed activity based level. This was to ensure no single approach was deterministic in setting our view of the efficiency of network companies’ expenditure. Network companies submitted cost-benefit analysis for a number of activity areas contained in their proposed investment. Where this was the case we carried out assessments with input from our technical consultants to examine the engineering basis for the work, and the network companies’ justification for this investment. Incentive regulation provides what is generally seen as the best way to try to reconcile the cost-benefit of investing in electricity resilience and deliver good outcomes for consumers. The companies gain from acting in the consumer interest and consumers benefit from the lower costs and better service. The point at which it is best to assess the purpose and the costs and benefits of large network investments may not be at the same time as the RIIO price control assessment. Therefore, for very large transmission investments, we have a mechanism known as ‘Strategic Wider Works’. This enables assessment of the need and efficiency of such a project during the control period. 4. What steps need to be taken by 2020 to ensure that the UK’s electricity system is
resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
There are a number of measures underway which aim to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the coming decade. For system resilience it is important that the system develops to incorporate:
Investment in flexible generation capacity
Increased DSR
Efficient and smarter network development
Longer term focused SO and environmental incentives
Offshore network development
Increased interconnection with Europe We are actively looking at this. In addition, we are implementing changes to the regulatory framework in networks including Distribution Network Operators (DNO) incentives through price controls and policies which will ensure that the UK electricity system is competitively priced. Given the high degree of uncertainty surrounding the composition of the energy system in the future, it is essential that our policies take account of this uncertainty. All of our impact assessments now cover longer-term strategic and sustainability issues, including the risk of lock-in to certain decarbonisation pathways and the risk to the diversity and resilience of the
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future energy system157. Resilience in markets The principal government policy in this area is EMR, and we are supporting it through our future ownership and development of the capacity market rules and our regulation of National Grid’s role in the delivery of EMR. We are also working with DECC to ensure that delivery of their other environmental schemes are efficient. Electricity Balancing Significant Code Review The EBSCR reforms align party interests with the interests of the consumer, and thereby allow parties that drive value to the consumer to realise a competitive advantage that reflects this value. These reforms support resilience – both in terms of the efficient response by the market to change (such as technological change), as well as development and deployment of innovative balancing solutions like DSR or storage. The reforms support security of supply to the extent that an ‘additional unit’ of security delivers a net benefit to the consumer. The EBSCR reforms play an important role in the development and deployment of flexible and reliable balancing solutions that accommodate a growing share of intermittent, low carbon technologies. They do this by allowing parties to realise the full value that these technologies deliver to the consumer (currently arrangements serve to under-value these solutions). The EBSCR reforms support delivery of competitively priced solutions by promoting (marginal) price discovery and ultimately incentivising parties to exhaust balancing solutions that can be deployed at lower cost than by the SO. DSR It is essential to create a clear and robust legal and regulatory framework so that DSR is a competing alternative to generation in the energy markets. DSR has the potential to reduce generation and network investments, thus enhancing security of supply and contributing to sustainable development. The NBS which National Grid have the option to procure, introduces a new mechanism, Demand Side Balancing Reserve (DSBR), by which customers can engage in this activity. The incentives on suppliers to encourage DSR will increase as the EBSCR changes sharpen the incentives on suppliers to balance their positions. Smart metering has the potential to enable many more customers to provide DSR. In order to maximise DSR, some changes to key industry settlement processes are required and these are being pursued via the Smarter Markets Programme. For the benefits of DSR to materialise it is important to improve the understanding of
157 For further information please see our Impact Assessment Guidance, pp21-23 https://www.ofgem.gov.uk/ofgem-publications/83550/impactassessmentguidance.pdf.
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consumers’ behaviour, including their willingness and ability to provide DSR. Our Consumer Empowerment and Protection158 work aims to assess uncertainties around the role of consumers in future energy markets, while our consumer research work provides insights into their consumption patterns and their understanding of the offers available. The smart metering roll-out will create new opportunities for parties to use the electricity system more effectively. Suppliers will have access to accurate consumption data and would therefore be able to offer time of use tariffs that reward consumers for shifting demand away from times of system stress. Also, new parties will enter into the market, offering innovative services and home management products to help manage their demand and as such provide DSR. SO role Market changes such as increasing renewable penetration, integration with Europe, and developments to the internal transmission network are already impacting on the SO’s role in balancing the system today and will continue to do so in the future. In addition, Ofgem projects159 and the Government’s EMR could also impact both upon the SO’s role and on the market in which it operates. Over the next few years we will need to ensure that the SO continues to be incentivised to deliver outputs to the benefit of industry and ultimately consumers. In our initial consultation on SO incentives,160 we proposed to commence work on considering how we motivate the SO in the future. We expect this to include encouraging the SO to take a more proactive and longer term approach to efficient system operation. We are aiming to introduce future incentive arrangements from April 2017. Resilience in networks and RIIO network regulation It is early days but we have already seen (and will need to see more before 2020) signs of fundamental changes in network company behaviour such as significant improvements in consumer outcomes (for example, customer service during storms) and, cost reductions in response to the RIIO price control framework. Innovation funding is also starting to provide significant benefits to consumers. The latest modelling indicates that the take up of low carbon technologies will drive significant DNO investment out to 2050. The roll out of smart grids could greatly reduce this cost, with our view of the potential savings achievable from smart grids in the RIIO-ED1 period (2015-2023) in our draft determination being £943 million161. We are already seeing
158 https://www.ofgem.gov.uk/gas/retail-market/market-review-and-reform/smarter-markets-programme/consumer-empowerment-and-protection. 159 Examples of Ofgem projects are the integrated transmission planning and regulation (ITPR) and future trading arrangements (FTA). 160 This consultation can be found here: https://www.ofgem.gov.uk/publications-and-updates/electricity-system-operator-incentives-incentives-2015. 161 More information on Ofgem’s assessment of potential smart grid savings for ED1 is available in the RIIO-ED1 Draft Determination Expenditure Assessment document: https://www.ofgem.gov.uk/ofgem-publications/89068/riio-ed1draftdeterminationexpenditureassessment.pdf.
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benefits through deferred investment as a result of the introduction and use of active network management162. RIIO network regulation Electricity distribution network companies in particular will need to start changing over this period, making greater use of smarter network technology to position themselves for the challenges through to 2030 and beyond. RIIO-ED1 is setting the revenue framework for the electricity distribution network companies covering the period 2015 – 2023. In July, we announced draft determinations for the electricity distribution companies163. This would see network companies spend around £17 billion on the electricity network assets while cutting bills for consumers. We expect to see the use of smart solutions using real time information about the network and automation technology to make more efficient use of existing infrastructure. They also allow active management of consumption and generation patterns. These solutions can reduce the need for investment to accommodate new connections and result in a network that is more flexible to the changing patterns of consumption and generation. Offshore Transmission Government support schemes will encourage further investment in renewable electricity generation. For this power to reach homes and businesses in Britain, fit-for-purpose electricity networks must be developed, particularly offshore. It is estimated that billions of pounds of investment will be needed to connect these projects. A step change in network investment of this kind calls for a more dynamic approach to the development of transmission networks: an open, competitive approach that is built on encouraging innovation and new sources of technical expertise and finance. To this end, along with the Government, we have established the competitive offshore transmission regulatory regime responsible for managing the competitive tender process through which offshore transmission licences are granted. Granting licences to operate new offshore transmission assets via a competitive tender process means that generators are partnered with the most efficient and competitive players in the market. This should result in lower costs and higher standards of service for generators and ultimately consumers. The regime aims to facilitate timely and efficient access to the networks for connectees. We look to remove barriers and set the right incentives to ensure timely connections. Interconnectors Electricity interconnectors have potentially significant benefits for consumers contributing to
162 An example of this is as part of the Orkney Smart Grid. 163 With the exception of Western Power Distribution areas which had been fast-tracked where the decision has been taken earlier.
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overall system resilience. We recently confirmed164 that we would extend a new regulatory approach (cap and floor) to facilitate investment in interconnection where that is in consumers’ interests. This would be applicable to new near-term electricity interconnectors. 5. Will the next six years provide any insights which will help inform future decisions on
investment in electricity infrastructure? We gather insights to inform future decisions through a number of areas in our work. These include research into DSR measures, supporting innovative measures by network companies and market observations from our regular monitoring activities. Markets Increased flexibility of the system with the development of DSR and increased integration of the single market improving interconnector flows are key developments that will help inform future decisions on electricity security of supply. We will also have information with regards to the effectiveness of the EMR reforms and a better idea of the impact of energy efficiency measures more generally. The Transitory Arrangements (TAs) within the Capacity Mechanism (CM) and the DSBR, to be implemented in Autumn 2014, will play an important role in improving the understanding of the potential for, as well as barriers to DSR. These two policies have been developed to establish a level-playing field for DSR to provide capacity and balancing services. Ofgem will administer the TAs and CM and review the rules underpinning this policy to ensure they do not create barriers to efficient use of DSR to improve the resilience of the UK electricity system. In addition, as more smart meters are installed, the next few years will be crucial in understanding the effectiveness of time of use tariffs to incentivise consumers to shift or reduce their consumption. We will be monitoring the number and types of tariffs to ensure consumers understand and can benefit from DSR. Our RMR evaluation (planned for 2017) will assess the extent to which RMR has enabled consumers to make informed choices on their energy consumption. Our expectation is that by building a better understanding of the choices available, consumers will be able to use electricity more efficiently and help support the resilience of the system. Networks Distribution and transmission network companies should provide insights over the next few years as innovations supported by our new regulatory approach are identified. As part of the current distribution price control we established the LCN Fund to provide support to innovative smart grid trials which would minimise the network costs associated with the transition to low carbon. This project will provide insights to inform future decisions
164 Ofgem, decision to roll out a cap and floor regime to near-term electricity interconnectors, 6 August 2014 (https://www.ofgem.gov.uk/publications-and-updates/decision-roll-out-cap-and-floor-regime-near-term-electricity-interconnectors).
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on investment. Up to £500 million was made available to the DNOs to help achieve this. All of the projects that have been funded through this mechanism should be complete by 2020. Learning from the projects that have been funded can be found on the ENA smarter network portal. We require all DNOs to fully disseminate learning from their trials so that new techniques can be adopted across the whole of the sector to maximise customer benefit. DNOs identified £405 million of savings from smart grids in their RIIO-ED1 plans. The plans all embrace benefits drawing directly on LCN Fund learning, including:
Lower DG connection costs through innovative connection offers and active network management.
Better informed network planning, following data collection in trials.
Real-time operation of assets following successful trials.
In addition to these benefits, we are proposing a further £400 million of savings in our proposed allowances for RIIO-ED1.
We have extended this approach to transmission owners as part of the new RIIO price control which includes a time limited innovation stimulus package to fund innovations where the commercial benefits may be uncertain. Our ‘innovation stimulus’ consists of three elements:
Network Innovation Allowance - set allowance to fund smaller scale innovative projects.
Network Innovation Competition - annual competition for funding larger more complex projects with the potential to deliver low carbon and/or wider environmental benefits to consumers.
Innovation Roll-out Mechanism – revenue adjustment enabling companies to apply for additional funding within the price control period for the rollout of initiatives with demonstrable and cost effective low-carbon and/or environmental benefits.
We expect the trials that are funded through these mechanisms to start delivering benefits before 2020, although it is likely that the majority of RIIO trials will deliver most of their benefit post 2020. 6. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will
new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
With reforms such as EMR and NBS being put in place, going forward Ofgem’s remit will also focus on likely future developments, such as intermittency and localised generation. These are taken into consideration when assessing security of supply and ensuring that National Grid has the tools it needs to manage the day-to-day functioning of the GB energy market. The changes in the generation mix in GB over the coming years will likely represent a fundamental change to the way the system operates. Increased intermittency will likely make it more challenging for market participants to balance their overall positions and,
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ultimately, for the SO to balance the system. This means that the SO’s role may need to evolve, and a more diverse set of tools to operate the energy system could be required. In the future, DSR, interconnection and storage are expected to take a bigger role as the volume of intermittent generation increases. Ofgem is reviewing barriers to the efficient use of DSR and storage through its Smarter Market Programme and is encouraging investment in interconnection through its Cap and Floor proposals. Historically, the SO has balanced the system by using conventional fossil-fired generators, supported by pumped-storage, interconnection, and to a lesser degree by DSR. Increasing amounts of intermittent generation, such as wind, are expected to come online in order to meet our climate change targets. The Contracts for Difference being introduced by DECC will incentivise investment in low carbon generation. Increased levels of renewable generation, from wind farms and solar panels, are making it more difficult for the SO to balance the system. This creates further challenges for the SO to maintain system security. National Grid as part of its ‘Operating the System in 2020’ initiative is examining ways of improving the resilience of the system. Recently, we have approved a modification to the Distribution Code aimed to help address this risk by changing some settings of distributed generation165. National Grid is also looking at the challenges presented by this changing electricity system on how it operates the system through its System Operability Framework166. There, National Grid is assessing the impact of the changes in generation mix and new technologies on the system, for example its impact on system inertia and voltage management. 7. What does modelling tell us about how to achieve resilient, affordable and low carbon
electricity infrastructure by 2030? How reliable are current models and what information is needed to improve these models?
Markets On the generation adequacy side, the Electricity Capacity Assessment model is Ofgem’s main tool to inform our position on security of supply. It was developed in 2012 in conjunction with National Grid. The suitability of the methodology has been consulted on with stakeholders every year to ensure it is robust and fit for purpose. We have also held industry workshops to discuss it. The analysis used within the published report is based on the National Grid’s FES. Even over the short timeframe examined, there are significant uncertainties for the supply and demand outlook. Indeed, it is these uncertainties that mean that no model could be considered comprehensive or completely ‘reliable’. We therefore attempt to account for the uncertainty through the use of sensitivity analysis around the core FES scenarios (pessimistic and optimistic sensitivities). This ensures that a wider range of plausible outcomes is considered within the analysis.
165 https://www.ofgem.gov.uk/publications-and-updates/changes-distribution-code-and-engineering-recommendation-g59-frequencey-changes-during-large-disturbances-and-their-impact-total-system 166 http://www.nationalgridconnecting.com/ensuring-future-electricity-networks-operability/
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The results of this modelling, and the implications for market resilience, are addressed in other questions and in our CA 2014 report. Networks On the networks side, the Transform model (developed by the Energy Network Association) has been a useful tool to help inform DNOs’ business plans for RIIO-ED1. The model uses information available today about technology costs and existing capacity on the network to calculate where ‘smart grid’ solutions are more cost effective than conventional investment. The model is only indicative but does provide a basis for DNOs to understand the cost savings available from smart grids. Ofgem has used the Transform model as parts of its assessment of the RIIO:ED1 business plans and it forms part of the evidence base for our proposals to make additional cuts to DNOs’ allowances. There is a governance process for the Transform model to allow it to be updated as and when the costs of ‘smart’ solutions change or as new ‘smart’ solutions emerge. This will ensure that it remains relevant going forward. 8. What steps need to be taken to ensure that the UK’s electricity system is resilient as
well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
As mentioned in previous questions (see questions 2 and 4), we have been working together with Government, National Grid and industry to make sure the market is on a trajectory to ensure consumer interests are protected now and in the future including 2030 and beyond. To achieve the objectives of the ‘trilemma’ in the future it is important to ensure that renewable subsidies help to encourage adoption of new generation technologies and drive down their costs. It is also important that the intermittency of some renewable generation technologies does not affect security of supply by ensuring that there is adequate and flexible supply capacity and effective demand management. Promoting energy efficiency is fundamental as it achieves all three objectives at once. Ensuring that regulatory structures can adapt to the changing energy system is also an important part of the process. It is uncertain exactly what the structure of the UK electricity system will be by 2030, and therefore we cannot definitively say what steps need to be taken by then to ensure that the UK’s electricity system is on a trajectory to decarbonisation in the following decade; however, we have some insight into its characteristics through the modelling of organisations like the Committee on Climate Change (CCC) and the offshore regime. Climate Change and Sustainable Development At Ofgem we have assessed a range of published ‘future low-carbon energy system model outputs’; our analysis broadly supports the CCC analysis167. It is worth highlighting that
167 We examined the Committee on Climate Change Fourth Carbon Budget Review – part 2 - http://www.theccc.org.uk/publication/fourth-carbon-budget-review/.
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energy system models seem to favour centralised energy systems based on a narrow range of ‘big’ technologies. There appears to be a knowledge gap on the characteristics of UK energy systems where there is a high penetration of embedded (local) generation (akin to the German Energiewende168). We are aware of only two modelled scenarios that examine this in any detail – an academic project ‘Realising the Transition Pathways’169 and the National Grid 2014 FES ‘Low Carbon Life’ scenario170. Our analysis indicates that at a high level, the characteristics of the 2030 power system are that:
• the power sector is substantially decarbonised; the CCC suggest a 2030 power sector carbon intensity of 50g CO2/KWh (down from around 360 CO2/KWh today)
• key large-scale electricity generation technologies (and to varying extents in different scenarios, distributed generation) are deployed at scale, including some mix of new nuclear, on- and offshore wind power, and fossil fuel power fitted with carbon capture and storage technology, together with biomass power and unabated gas generation (to provide system flexibility) – unabated coal appears to play very little role in 2030
• electricity demand is higher, driven by increased take-up of electric vehicles and electric heating technologies, such as heat pumps
It follows that the steps that need to be taken by 2030 to ensure that the UK’s electricity system is on a trajectory to decarbonisation in the following decade are that:
carbon budgets continue to be met; the 2nd carbon budget has been met; the UK is on a trajectory to meet the 3rd and 4th carbon budgets, and the 5th carbon budget has been agreed
the Contract for Difference (CfD) regime has successfully deployed a range of low-carbon energy generation technologies
policy developments instil longer-term confidence for strategic investment in low carbon energy generation, e.g. of market structures that can support capital-intensive, low operating cost investments which are either not covered by CfDs, or once CfDs expire - a rising floor price to carbon could make an important contribution to this
UK carbon objectives are understood within the context of the EU 2030 Energy and Climate Package and global carbon ambitions
options for providing electricity system flexibility, facilitated by a smart grid, such as DSR, energy storage, interconnection and adaptable thermal plants, have been effectively and efficiently developed
the smart meter roll-out has been completed
168 Energiewende (German for Energy transition) is the transition by Germany to an energy portfolio dominated by renewable energy, energy efficiency and sustainable development. 169 An academic consortium seeking to explore what needs to be done to achieve a transition that successfully addresses the energy policy 'trilemma' i.e. the simultaneous delivery of low carbon, secure and affordable energy services - http://www.bath.ac.uk/realisingtransitionpathways/about-us/index.html. 170 Low carbon life is one of four scenarios published by National Grid in their 2014 Future Energy Scenarios - http://www2.nationalgrid.com/uk/industry-information/future-of-energy/future-energy-scenarios/.
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Ofgem continues to grant licences to operate new offshore transmission assets via a competitive tender process so that generators are partnered with the most efficient and competitive players in the market.
completion of Ofgem’s ITPR project leads to measures to best facilitate longer-term development of the electricity system including, where appropriate, integrated systems between onshore, offshore and cross-border projects
9. Is the technology for achieving this market ready? How are further developments in
science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience?
Ofgem is technology neutral and as such, we would not comment on the best emerging energy technology. In terms of game changing technologies, increased diversity of generation will tend to improve security of supply by reducing over-reliance on any one type of technology or fuel. We recognise the important role that emerging technologies may have in the GB energy system. Our interest would be to make sure there is always a robust, yet agile, framework for electricity supply which will enable us to keep the lights on. We view support for emerging energy technologies balanced with affordable bills as being in the long term interest of consumers. In our network regulation, part of the motivation for changing to our new RIIO approach was to encourage the networks to think differently so as to be able to support new technologies. While retaining our neutrality in terms of technology, some technologies e.g. in generation will provide new and different challenges to networks and it’s important that they can cope with these to retain a true level playing field. 10. Is UK industry in a position to lead in any, or all, technology areas, driving economic
growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system?
Ofgem is technology neutral and as such, we would not comment on the best emerging energy technology. 11. Are effective measures in place to enable Government and industry to learn from the
outputs of current research and development and demonstration projects? Where we have encouraged network companies to innovate or consider innovative solutions one of the key principles has been to make sure that shared learning happens. The governance of our LCN Fund and our new Network Innovation Competition under the RIIO controls requires this to happen. An innovation strategy formed part of RIIO business plans and evidence of how knowledge would be retained and shared were important elements. 12. Is the current regulatory and policy context in the UK enabling? Will a market-led
approach be sufficient to deliver resilience or is greater coordination required and what form would this take?
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While we believe that a market-based approach can deliver resilience, the revolutionary changes associated with moving to a more dynamic market may require some initial coordination. To support the resilience of the UK electricity sector it is important that parties work to establish more efficient, dynamic and innovative energy markets. To do so, they need to understand the value of using flexible measures (such as DSR) to become more efficient in the way they operate in the market and use the electricity system. A market-based approach can help reveal the true value of DSR and create the right incentives. Our work to establish a framework that formalises cross-parties interactions when using DSR aims at enhancing coordination and communication so that new opportunities and incentives to use DSR are revealed to parties within the existing market model. Our work on the EBSCR, SO incentives and the Electricity Settlement Reform, aim to ensure that the value of flexibility (and the costs of not being flexible) is correctly signalled in the market. Ofgem is assessing the potential impact of future developments including increased levels of low-carbon generation, storage, DSR and European interconnection, on the effectiveness of current market arrangements through the Future Trading Arrangements (FTA) Forum. The FTA Forum brings together informed and influential industry players to identify emerging issues for GB trading arrangements and build consensus around necessary and desirable changes to current arrangements. Through the FTA project Ofgem is also considering alternative future market designs that may improve market performance and consumer outcomes in a low-carbon, integrated electricity system. This work will assess the fundamentals of the GB market design and also consider the applicability of well-regarded overseas arrangements in the GB context. The development of the RIIO model for network price controls also encourages network companies to take responsibility for developing and justifying a long-term strategy for delivering the network services that their customers value. While the previous approach to price controls had delivered cost efficiencies and service improvements, RIIO identifies a number of different output categories which encourage network operators to take a longer term view and provide an effective focus for meeting consumer needs. 29 September 2014
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Ofgem – Oral evidence (QQ 176-185)
Evidence Session No. 15 Heard in Public Questions 176 - 185
TUESDAY 13 JANUARY 2015
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Hilton of Eggardon Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Baroness Sharp of Guildford Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston
_________________________
Examination of Witnesses
Rachel Fletcher, Senior Partner for Markets, Ofgem, and Maxine Frerk, Senior Partner for Smarter Grids & Governance: Distribution, Ofgem
Q176 The Chairman: I welcome our two witnesses from Ofgem. Thank you for joining us this morning. We are being broadcast, so I am going to ask now for the record if you would introduce yourselves. If either of you wants to make an opening short statement, please feel free to do so.
Rachel Fletcher: I am Rachel Fletcher. I am the senior partner for markets at Ofgem. Among my responsibilities is the analysis of security of supply and the regulation of National Grid as a system operator.
Maxine Frerk: I am Maxine Frerk. I am the senior partner responsible for all aspects of regulation of the distribution network companies.
The Chairman: And you are happy that we go straight into the questions now?
Maxine Fletcher: Yes.
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Q177 Lord Patel: My question relates to who is ultimately responsible for maintaining the resilience of the UK’s electricity supply. Within that, what is the role of Ofgem, and how does that relate to the Government, National Grid and the electricity generation companies?
Rachel Fletcher: Your question actually partly answers the first part of your question. Really, responsibility relies on the interactions of several parties—namely, government, industry and us as regulator. Put very simply, the Government’s role is to set overall policy objectives, including, in the case of security of supply, what we call the reliability standard. Industry’s role is to deliver that security of supply, but it works within a framework that we as a regulator set to ensure value for money for consumers and quality of service in the delivery of the networks and the overall operation of the system.
Lord Patel: Maxine, would you like to answer before I come back on that?
Maxine Frerk: My answer is basically the same.
Lord Patel: So if the lights go out, who do the citizens blame?
Rachel Fletcher: It is really important to say that we have enjoyed a huge degree of system resilience and reliability in Great Britain, and I have no reason to suspect that that resilience is any less going into this winter than it has been in recent years. However, if the lights were to go out and we were to have uncontrolled consumer disconnections, I am certain that there would be a very careful review of what led up to that point, and questions would be asked about whether the level of risk in the Government’s reliability standard was still appropriate for the country as a whole. Questions would be asked about our role and whether we had stood in the way of any actions by the companies in the market, and about the way the market and the system operator performed. The short answer is that it would depend on what had led us to that situation.
Lord Patel: I am tempted to ask what your answers would be to all those questions.
Rachel Fletcher: Well, I am pleased to say that the lights have not gone out. It would depend on the specifics. For example, if something completely predictable had happened on the system and no appropriate measures had been put in place to address that, really serious questions would be asked of National Grid as system operator and of Ofgem. The situation at the moment is that several years ago we saw a tightening in electricity margins on the system; we foresaw the situation this year and next year in particular, and we took measures and put in place supplementary balancing reserves, particularly to protect the levels of resilience and to keep them within the reliability standard that the Government have set.
Q178 Lord Hennessy of Nympsfield: Can I follow up on your roles? We have had plenty of evidence about the 4% margin over the next two years that you have just referred to. It seems to an outsider to your world like me that there is a very thin blue line of electricity between us and potential outage and social and industrial dislocation on a considerable scale. That is very visible once it starts happening, and it would make the political weather. Do you as regulators have a duty to protect not just the citizen as consumer but in the wider sense of speaking truth unto power? Have you had occasion so far—and would you do this in future if you had such occasion—to warn publicly that that thin blue line of electricity, the 4%, was simply inadequate? Is the regulator in a position—in fact, I cannot think of anyone else who could do this on behalf of the consumer—to say that and make it public? And would you?
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Rachel Fletcher: Absolutely. Every year we publish what is known as a capacity assessment, where we provide a forward look of expected margins on the system over a four-year or five-year period. We work very closely with National Grid in doing that, but effectively our role is to provide a robust challenge to the assessment that National Grid is making, and to take a view ourselves on what margins are likely to look like and what risks and sensitivities there are around those projected margins. It was precisely because we were doing that work that towards the end of 2012-13 we started talking about the need for the supplementary balancing services that have been put in place for the middle of this decade. So yes, we see it as our role to look ahead, spot issues and then try to do everything in our power, working closely with the system operator, to ensure that that resilience is maintained. Once we get further into the end of this decade, the Government, through their capacity market and as part of the electricity market reforms, have already taken legislative powers to introduce a new mechanism to deliver the margins and the security of supply that we need as a country. That slightly dilutes the role that Ofgem has once you look towards 2018 and further ahead, but certainly in the intervening period, yes, we see that as our role.
Lord Hennessy of Nympsfield: But 4% is not enough. You are the security of supply person at Ofgem. Is it your personal view that we are on too thin a margin?
Rachel Fletcher: The Government’s reliability standard is our touchstone here; overall it is a political decision about the trade-off between resilience and cost, and the Government have made that decision themselves—rightly, in my opinion—and set that in legislation. Four per cent is about the right margin, with today’s mix of generation, that you would need to meet that standard of three hours’ loss of load expectation. When you look even six to eight months ahead and you are trying to project what the margins might be, there is always a degree of uncertainty about what is going to happen to demand and to generation plant. When we did that look ahead towards the end of last summer, there was even more uncertainty, given that we had had a number of fires and of course the Hartlepool and Heysham plant had come offline because the crack in the boiler spine had been detected. In that context, then, and given the uncertainty around the margins we were likely to have this winter, we felt that it was appropriate that National Grid went ahead and procured a supplementary balancing reserve, which has effectively dealt with that level of uncertainty and brought margins on the system to within a more comfortable range.
Lord O'Neill of Clackmannan: Is it therefore the case that the buck does not stop with you or with Ofgem but with the Government, because they have set the target of a three-hour shut-off minimum? Is that correct?
Rachel Fletcher: As I said before, it would have to depend on the specifics.
Lord O'Neill of Clackmannan: But how do the Government come to the judgment that this is what is required? How do we get from the Government’s decision to 4%? How do they come to their decision? I am not very clear. You are saying that National Grid thinks we can do it and we think we can do it, but is it at the right level in the first place? Or do we have to ask the Minister?
Rachel Fletcher: That would be a question for the Minister. The methodology that they have used is a widely accepted one—
Lord O'Neill of Clackmannan: Accepted in the UK or, let us say, in Europe?
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Rachel Fletcher: Internationally. The methodology that they have used has involved estimating the value that consumers put on security of supply, and I think people in this room will appreciate that that is not a straightforward thing to do. They have applied a methodology to put a value on what we call “value of lost load” and then, using that value, to work backwards to a reliability standard, which is then translated into a margin of around 4% with today’s generation mix.
Q179 Lord Peston: Following Lord Hennessy’s point, you seemed to be answering his question in terms largely of the variance of demand causing the problem, given the available supply. What about turning this on its head? Is there a serious problem with the variance of supply? To take an extreme example, the 20,000 householders who still do not have any electricity in Scotland could say, “Well, someone ought to have put all those pylons underground”, to which the answer is, “That’s so expensive that it’s not worth while delivering electricity to you”. Would that be the right answer?
Rachel Fletcher: The reliability standard that the Government have set relates specifically to generation capacity and the adequacy of it to meet consumer demand. There are then separate questions to be asked about the standards to be used when investment is being made in networks, which perhaps it would be better for Maxine to answer.
The Chairman: So we are talking about different standards for distribution and generation, are we?
Rachel Fletcher: Yes.
Maxine Frerk: On the distribution networks, and indeed networks in general, again, the Government set standards that say, for example, that gas networks are designed to anticipate a one in 20 worst level of weather in winter. In terms of the technical standards for designing the networks, the Government set the level of resilience that they require. Through our regulation, we give the companies incentives. The issues in Scotland are how many operational staff you have and how quickly you can respond. In fact, everyone is now back on supply in Scotland.
Lord Peston: Are they? Oh, that is good news.
Maxine Frerk: They were connected last night. In some sense, in what was quite a difficult situation given the severity of the weather, that was a good response. Within the price control regulations the companies have incentives, and they can either earn money or lose it depending on how many interruptions they have during a year. They also have to pay compensation to customers, which again gives them an incentive to reconnect. Those are all set through a process of consultation with stakeholders when companies develop their business plans that they put to us.
Lord Peston: To go back to the question of where the buck stops, which is what got us started here, do I understand it that if, say, you are consumer in Scotland and you have pylons delivering your electricity so you know that you might be in trouble in bad weather, the people to whom you have to address remarks are the Government, not you. Is that right?
Maxine Frerk: No.
Lord Peston: If I want my electricity to come underground—
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Maxine Frerk: That is more about the business plans that the companies are putting together. You would be putting your case to the companies as they develop their business plans, but they would be saying, “Are you willing to pay the costs of having that undergrounded?”. Companies have typically done work around their worst served customers. For example, people on the remote islands in Scotland have not had any transport for the last 48 hours either. There is a balance that they have to make regarding how much they are willing to pay to ensure that they could always be guaranteed levels of service. That trade-off is made through the process of consulting local stakeholders.
Lord Peston: So the answer that you would give is that if you want to go and live on an island off Scotland, you have to pay for it?
The Chairman: It is called the island mentality, I think.
Maxine Frerk: Various costs are recovered across all customers in that company’s distribution areas, not specifically from remote areas.
The Chairman: Can I move on to Viscount Ridley?
Viscount Ridley: I was not trying to catch your eye.
The Chairman: No, but I have you down as asking a question.
Q180 Viscount Ridley: And I will quickly find it. While I am doing that, my sheep-farming friend on the Isle of Coll says that he is running out of card games to play by candlelight. The question is about Ofgem’s capacity assessment showing that the capacity margin will be squeezed over the next two winters. How is that expected to affect the resilience of the electricity system? This covers some of the ground that we have gone over already.
Maxine Frerk: My answer is that it is not expected to affect the resilience of the system because we have already put in place arrangements for National Grid to purchase a supplementary balancing reserve, which brings us to the kind of level of resilience that we have been used to having on the system over the past few years.
Viscount Ridley: Have you been getting accurate enough information about the status of plants, with regard to the unplanned outages that we have seen, to be able to deal with and unmothball mothballed plants and things like that?
Maxine Frerk: We get very good near-term or short-term information through a number of different sources. Some of it is just through our own surveillance about what is happening, but the companies themselves, through new European legislation that tries to ensure that we have transparent and well functioning markets, have to publish notifications of unplanned outages and mothballing decisions, for example. That provides us with an even better source of intelligence than we have been used to getting. We share the intelligence that we have with National Grid and DECC, so between the three organisations we are pooling the information that we have. That meant, for example, that when it came to deciding how much supplementary balancing reserve the National Grid should be purchasing for the 2014-15 winter, those decisions could be made on the basis of good, accurate and up-to-date information. When things become a bit less accurate, of course, is when you start looking several years ahead. That is why our own capacity assessment has sensitivities within it to account for that degree of uncertainty, particularly about what is going to happen to supply over a two or three-year time horizon. I have to say that one of the things that will help us in doing that now with a bit more certainty is that the capacity market, the first
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auction of which has just been run, helps to reveal information about which plant you might expect to be on the system come 2018 or 2019, so that already begins to make our job and the job of National Grid that bit easier.
Viscount Ridley: Is the unmothballing of plants proving easier or harder than expected? Maybe that is too general a question, but do we have experience of bringing back a gas plant that has been mothballed for a few years?
Maxine Frerk: You are getting into a level of technical questioning that is a bit beyond my own knowledge, but certainly when National Grid went to procure new balancing services, some of the most competitive plant was plant that was currently on the system rather than plant that had to de-mothball. It is certainly the case that the longer a plant has been in mothballs, the more expensive it is to bring it out and the more technical uncertainties there will be about that plant’s reliability.
Q181 Baroness Sharp of Guildford: My question follows on from the discussion we have just been having. Do you feel that we now have the right policy framework in place to ensure that the electricity system resilience is sufficient in the short and long-term? In the short term, is the right balance being struck between supply and demand measures in the national balancing services being implemented by National Grid? In the medium term, is there a risk that the capacity market will support too much capacity and cost consumers more than it should? For example, why do suppliers all receive the price at the marginal bid, whereas they may well have bid at a much lower price? Do the capacity market arrangements fail to encourage sufficient demand-side response and the use of interconnectors rather than the supply-side response here?
Rachel Fletcher: I will take that question in chunks because there are a number of dimensions to it. I think we have the right policy framework in place in the short and medium term, with the combination of the new balancing services and the capacity market. However, and I think your question alludes to this, there are a number of dimensions to the capacity market policy design that are still work in progress, particularly the participation of demand-side response and interconnectors in the capacity market. As a regulator, we are certainly very keen to see those elements of the capacity market design become firmed up sooner rather than later. As an organisation, we believe fervently in the potential of demand-side response to provide a cost-effective way of helping us to meet resilience on the system. While the Government have taken many good steps already—for example, there is a transitional option for new forms of demand-side response that the Government will be running towards the end of this calendar year, and that is a good way of trying to provide a testing ground for demand-side response; there are still some questions, particularly around the duration of contracts that are up for grabs for demand-side response in the main capacity market, which are limited to one year. There is some thinking to be done by the Government about whether the same principles that have been used to decide on the duration of capacity market contracts for generation should also be applied to demand-side response.
The Chairman: Why is the timescale so much shorter for demand-side response than it is for these other management contracts?
Rachel Fletcher: When you talk about timescales, I am not quite sure what you mean.
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The Chairman: You are talking about one year for demand-side management contracts, whereas that would not feature on the new balancing services, where you would expect a longer term.
Rachel Fletcher: This is really the question I am raising about the capacity market and some future design issues that need to be considered by the Government about the way that market works. As I said, there is—in our mind, at least—a need for the Government to go back to first principles and say, “We should be applying the same principle to all participants in the capacity market, whether they be generators, demand-side response providers or indeed interconnectors, when it comes to deciding the duration of the contract that is on offer”. Another area for the Government to consider is, as your question alluded to, the role of interconnectors. The Government will be including interconnectors in the 2015 capacity option, but all the work that they have done in bringing them in for the 2015 option has raised a number of questions, particularly around the fact that interconnectors are technically different from generators—for example, they export as well as provide imports and contributions to security of supply.
Baroness Sharp of Guildford: The evidence that we received before Christmas certainly indicated that there was potentially a considerable development in the use of interconnectors that we could look to over the longer term.
Rachel Fletcher: Absolutely. We agree very much with the thrust of what the Government are trying to do. When it comes to procuring for resilience, the contribution that interconnectors make needs to be taken into account, whether that is deciding how much generation you procure through the capacity market or allowing interconnectors somehow to participate in the market itself. Some of the fine design details of how you do that still need to be worked out, and we are keen to work with the Department for Energy in working up those design details.
Viscount Ridley: I have a quick point regarding interconnectors. I was looking at some data the other day showing how the interconnector with France has been operating. It is nearly always flowing into this country pretty much full-bore, but there was a period when it suddenly flowed out of this country for a few weeks about two years ago. When you drill down into what was going then, you find that it was very cold in Germany. The huge German demand for power was drawing a lot of electricity out of France, France suddenly had a need and it started drawing electricity from us. Is it possible that there are conditions under which interconnectors could increase our problems by making demand greater elsewhere even when our own demand is greater, and could reduce reliability?
Rachel Fletcher: It is absolutely possible, which is why there is still unfinished business in the design of the capacity market. The way interconnectors flow is set out by European rules. Those rules say, effectively, that interconnector flows are determined by price differences on either side of the interconnector. So in the situation that you have just explained, where the prices on the continent might be higher than ours, it is to be expected that the interconnectors will export to the continent, not import. Generally, that would be of no concern—I think it is how we would all expect interconnectors to behave—but it creates technical difficulties when it comes to assessing the extent to which you can rely on interconnectors to provide you with a contribution to resilience when you most need it at times of system stress. Indeed, that is an exercise that the Government are going through
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with regard to their current investigation into what they are calling the appropriate de-rating factor to apply to interconnectors that might participate in next year’s capacity option.
Lord Wade of Chorlton: How is that decision made? Is it an automatic decision by computer, or does someone make it?
Rachel Fletcher: It is an algorithm.
Lord Wade of Chorlton: So once the interconnector goes one way or the other, someone looks at the price list and it is decided automatically. There is nothing that anyone can do about it.
Rachel Fletcher: With one exception, which is—and you may already have heard this from National Grid—that the system operator has contracted for what they call emergency services on the interconnector. So if we are in a particularly tight situation, National Grid can call on emergency interconnector support into Great Britain, but that would not be a normal functioning of the market; it would be National Grid intervening and taking emergency measures.
Q182 Lord Winston: How is resilience taken into account by Ofgem’s regulation of the transmission and distribution networks? How does the RIIO model work? Indeed, does it work?
Maxine Frerk: If you look back over time, we have had a good record with our regulation of the networks delivering improved resilience. Over the past 20 years, customer interruptions as a result of network problems have fallen by 30% as a result of the incentives that we are putting on the companies. RIIO was an attempt a few years ago to look at how we would update network regulation, recognising the increased challenges that we have as the networks have to evolve a lot to cope with more distributed generation and the challenges that you as a Committee have been talking about. RIIO stands for “revenue”, which is the revenue that the companies get from running the networks, which is determined by a set of “incentives, innovation and outputs”. We are trying to ensure that there was a real emphasis not just on how much revenue the companies are allowed but on what they have to deliver on that revenue. In terms of resilience, in the short term they have a mixture of sticks and carrots regarding getting the number of interruptions and minutes lost down; if they outperform the targets we have set they can earn additional revenues, but if they fall short they lose revenue. As I said before, they also have to pay out to customers under the guaranteed standards. That puts incentives on to the companies to make their networks as resilient as possible and to respond when issues arise.
Maxine Frerk: So we try to ensure that companies put forward to us business plans that they have consulted their stakeholders on, that are well justified and that include what they can do in terms of network performance and in terms of cost. We look across the different companies and benchmark them, looking at what stakeholders are feeding through in response. As part of the framework, to ensure that they are not just taking short-term efficiency measures, effectively cutting the maintenance of the network, we have medium-term network output measures that they have to achieve, which is us effectively looking at their asset health at the end of the price control periods to ensure that it is in a better condition at the end of the period than it was at the beginning in terms of the resilience of those underlying components, and incentives around innovation to get them to look really longer term and think about proposals and put them forward to us, for which they can get
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innovation funding, to explore the impact of increased distribution generation and how they might run their networks in a smarter way to ensure that they are really thinking about how to get that resilience right into the future.
Lord Winston: We heard some evidence that the recent price control settlement for National Grid was “highly challenging”. I wonder whether you would comment on whether there is a risk that the price control may prioritise efficiency over resilience.
Maxine Frerk: I think companies will always say that their price controls are challenging. In the session that you had with them, they accepted that they could meet those efficiency standards and still meet their licence obligations through that price control. In fact, for the first year of price control on the electricity transmission side, we had allowed National Grid £1.8 billion of revenue, and they have spent only £1.4 billion. They may have said that it was challenging but they have looked at how they can engineer and restructure their procurements in order to deliver very big efficiency savings. Clearly, we then need to ensure that that is not being done—because they benefit from having come in below our allowed revenues—at the expense of letting the networks deteriorate. We will be holding them to account for the outputs that we have set, and that is how we ensure that. The regime gives them an incentive to drive for efficiency, and then we hold them to account for delivering the outputs to ensure that they are not simply cutting costs.
Lord Winston: To come back to the 4% margin, we had some evidence from John Roberts of the Royal Academy of Engineering, who had looked at two episodes, one in December 2010 when there was 10 days of very cold weather and the other in May 2008 when two major power stations had operational problems. He asks, “What would happen now if there was an extraordinarily cold spell? How do we cope with that?”. The question really is the 4% margin again, of course.
Rachel Fletcher: The loss of load expectation, the Government’s reliability standard, effectively has to be met in a range of different scenarios. It is not a standard that the Government look to be met in a normal winter, because actually there tends to be no such thing as a normal winter. That in particular is why, when we ran the numbers for the current winter and factored in cold weather or further mothballing, for example, we felt that it was prudent to allow National Grid to purchase the new balancing services so that it had that extra tool, particularly to manage those more extreme scenarios. The other variability on today’s system, of course, is how much wind varies, which is another factor that was taken into account. A low-wind scenario is another scenario that has effectively been covered through the procurement of those new balancing services.
Lord Rees of Ludlow: Following up on those stress tests done by Dr Roberts, one new issue is going to be cyber threats. Here the past is no guide to the future at all, and I wonder if there is any concern that this might be an aggravating threat—more to the distribution network than to generation, I guess—and whether, in the light of that new possible threat, you feel that the safety margin is adequate and indeed if the Government’s requirement of three hours is indeed the right parameter.
Maxine Frerk: I think you are right: obviously, you can have a cyber threat either to the networks or to individual power supplies. As Rachel set out in the beginning, in terms of the roles of the different parties, companies are responsible for ensuring that they put the necessary protections in place, but this in particular is an area where the Government, because they have much more of an understanding of potential threats and inside
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knowledge, will set out certain steps that need to be taken by the companies to deal with cyber threats or indeed any kind of threats. Our role is to ensure that companies are allowed the expenditure through their price controls. Because this is an area where things can change very rapidly, on the network side one of the specific reopeners is where the companies can come to us and ask for additional money in the middle of a price control if they need to in order to deal with any of those kinds of issues.
Lord Rees of Ludlow: But who does stress tests on this part of the system?
Maxine Frerk: It is for the companies to work out that they have appropriate protections in place to deal with threats and knowledge. The Government will give them the best information that they have about the types of threats that they may see emerging.
Rachel Fletcher: The Government have also specified what they call critical national infrastructure and put particular measures in place that they would like on that infrastructure. Again, the delivery of those measures and the fine design of them would be for the companies themselves but, as Maxine says, it is our role to ensure that the cost that consumers pay for any of that work is efficient.
Q183 Lord Hennessy of Nympsfield: From your stress testing work and the results that you have seen, what are your single greatest worries about all this, on an individual basis, given the duties that you have?
Rachel Fletcher: From my point of view as the senior partner for markets, the biggest challenge that I see is less to do with short-term resilience and more, now that we have the electricity market reforms in place, to ensure that those reforms and the overall electricity market work harmoniously together to keep costs down for consumers, as well as to provide goods investment signals and operational signals. We have come over a hill, if you like, in concerns about resilience. That is not to say that there are no risks at all because no system can ever be 100% reliable, but I feel confident that we have the right policy arrangements in place in the short and medium term for resilience. The real question is more than one of not losing sight of the important role that the wholesale market itself plays in providing investment and operational signals and ensuring that we do not lose the important role that that market can play, with all the inevitable attention that there has been on implementing the capacity market and EMR more generally.
Maxine Frerk: On the network side, clearly the networks are vulnerable to weather. In my new role, I pay a lot more attention to the weather forecast than I used to. Sometimes you get stress testing, and indeed we have had stress testing in Scotland this weekend. The bits that worry me therefore are the things that we do not have the chance to test very often, or indeed have never had the chance to, such as an emergency that spans a much wider area and goes beyond the energy networks. A major terrorist incident in London, for example, would have ramifications for the energy networks but would have much wider ramifications too. In some sense that is beyond my remit, and obviously thinking about those kinds of issues is the kind of thing that the Government do through their E3C committee and others. Those are the kinds of scenarios that we do not have the opportunity to stress test in reality, but we have emergency planning, role-play situations and other things to try to understand what to do in those situations. Clearly, though, we have never had to work through one, so we have not seen what would actually happen in that kind of situation.
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The Chairman: But the weather-related issues on distribution that you refer to are not always wind and storms; they could be flooding. Were you in post last year when flooding in the south-west was a major issue? Did that stress the system and cause problems?
Maxine Frerk: I was not, but I was involved in the investigation that we did to follow up on that. It was an example where, although there were exceptional circumstances last Christmas and the people working on the ground were working in difficult conditions, the companies did not do all that they could have to communicate with customers to anticipate the weather. We have made sure that the lessons were learnt from that experience last winter, and what we saw this weekend—we have not yet had a full review, but this is my sense of it—showed that a lot of those lessons were learnt regarding, for example, communication with customers. We have had a much better experience this time around than we did with the storms last Christmas.
Baroness Manningham-Buller: You have partly answered the question about what lessons were learnt from last Christmas, but I would like to pick up on a particular one under that heading. You referred earlier to all the distributors having business plans. Why did you reject all but one of them?
Maxine Frerk: That is a glass-half-empty or glass-half-full type of question.
Baroness Manningham-Buller: I did not realise it was.
Maxine Frerk: In the way that we used to do price controls, we always went through a number of rounds with the companies when they put forward their initial proposals, such as consulting on draft determinations. One of the aims of the RIIO framework was to try to get companies to put in better plans up front. Now we have the ability to fast-track companies; if the first plan is really good, they can be saved all the effort of going through the iterations they used to have to go through and can get on with running their businesses. I would look at it and say that we were very pleased to find that one company, WPD, put to us a sufficiently good business plan that we were able to fast-track it and it did not have to go through that process. We continued to scrutinise the business plans of the other companies and do the benchmarking and all the other analysis that we have traditionally done. That was justified as, in that part of that process, the difference between what they initially put to us and what we put out in our final proposals was £2.1 billion in efficiency savings that we were able to identify. We rejected their business plans but that is not necessarily a criticism; that is much more the normal process. The unusual ones were the ones that were able to fast-track because they were good enough.
Q184 Baroness Manningham-Buller: Thank you for that explanation. I want to ask about the Low Carbon Networks Fund. Is it sufficiently incentivising companies to invest in smarter, more responsive grids?
Maxine Frerk: I absolutely believe that it is. To recap, the Low Carbon Networks Fund is money that we made available through the last distribution price control; £500 million was available for the companies to bid for if they had proposals for new innovative solutions that they wanted to test out. When I went up to Aberdeen last year for the annual conference, I had a really positive reception and positive comments from small companies that are part of that infrastructure, as well as from the distribution network companies themselves, about the fact that we were enabling all this innovation, and there were huge numbers of stands demonstrating all sorts of different products that are coming forward. This has put GB in a
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really strong position in Europe. Having been relatively behind the curve, we are now one of the leading countries in Europe on that smarter agenda, whether it is storage, how to cope with more renewables or managing frequency. We do not have the Low Carbon Networks Fund but we now have an equivalent, the network innovation competitions, which cover transmission and gas as well, so that we can begin to look a little more across the piece, not just at the distribution networks.
Baroness Manningham-Buller: And how do you decide which of these splendid innovations are the ones you, or the companies, are going to run with?
Maxine Frerk: So we have an annual process where companies can put forward proposals. We have an external panel of experts, a mixture of academics and business people, who form a view based on those proposals. Last November we approved eight additional projects at the network innovation competition and rejected two of those that had been put forward to us because they had not given enough evidence. Having been positive about this, though, I do not want to sound complacent, so we are carrying out a review, which will be kicking off very shortly, looking back at the experience of the Low Carbon Network Fund to see if there is more that we could have been doing or different criteria that we could have been applying to take forward that learning into how we run the network innovation competitions in future.
The Chairman: You said that you were impressed by the innovation opportunities that you saw in Scotland. Taking a different utility sector—water, for example—I have often heard it said by small SMEs, or spin-outs from universities, that it is very difficult sometimes to get the large undertakers to take seriously some of the innovative ideas coming out, particularly in the field of IT regarding monitoring systems, leakages and the like. Is this to any extent true in the electricity generation sector? After all, you have the same problem of large incumbent organisations, very often not always exposed to the sharp cutting edge of what is going on in the university sector spin-out companies—or are you confident that they are open to innovative ideas?
Maxine Frerk: I think our innovation fund has had a big impact in that space. A number of small companies and academics are involved in supporting some of those bids. There is also an organisation, which we played a role in helping to get set up, called the Energy Innovation Centre, which acts as a broker between those rather big and perhaps unapproachable distribution network companies and small parties. That is one of the steps that we took a while ago to try to help, and to do a bit of matchmaking, to get those organisations talking to each other. I am not saying that we have got it all right—I know that there are issues with intellectual property and other areas that have been raised with me that can make life harder for small players, and that is the kind of thing we want to look at as part of our review—but we have a good track record here in having got a lot more small players into the innovation space in energy.
Q185 Baroness Hilton of Eggardon: To follow on from that question from the Chairman, it has been suggested that a systems architect is needed to co-ordinate better and drive strategy forward. Do you think such a thing is necessary? Could Ofgem fulfil that role? If so, would you need additional functions, powers and legislation to carry it out, or do you have sufficient already?
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Maxine Frerk: We absolutely recognise the problem being described, which is that as we move from a very centrally planned and very stable system to one that is much more distributed and complex, we need to look end-to-end across the system at distribution, transmission and the things that are being attached to the distribution network. I would be very reluctant to have another organisation set up, because the big issue is always accountability. Already, as we discussed earlier, there is the question of what DECC’s role, our role and National Grid’s role is, and having another party in the space would only risk further confusing that accountability.
The systems architect that has been described is much more on the engineering side. We have engineers in Ofgem, but Ofgem is essentially an economic regulator looking at the framework, so there are elements of what we do that can help to contribute to that space. Something that we have been talking about internally is National Grid’s own role as the system operator. We have some proposals out at the moment that we are consulting on, such as an enhanced role for National Grid as SO that would require it to be more proactive and think more about planning further ahead, rather than simply being a reactive organisation. We have two codes at the moment, which the IET may have talked about: the grid code and the distribution code. You need things that look across the piece of those two codes and some of their challenges. We have already had examples of where they have been able to set up a joint work group to look at the question again. I think one of your previous witnesses talked about inertia and the impact that having more distributed generation had on the rate of change of frequency—again, those are some technical issues within the network—and the two code panels were able to work together to solve that. Within Ofgem, we can look at whether we should be doing more to formalise those sorts of arrangements. There are things that we should be doing and more discussions that we can have through the Smart Grid Forum, which brings different parties together to look at some of the future challenges. There are elements of what is needed from a systems architect that are happening in different organisations, and it is probably more about ensuring that we have all those covered and thinking about the roles of the grid in that space and the way we manage some of the code panels. That could go a long way towards addressing those issues without creating another body.
The Chairman: Thank you. We have reached the end of the session. We are most grateful to you both for your help. You will of course get a written transcript of the proceedings, so do correct any minor errors. If there is any further information you wish to impart to us in writing, please feel free to do so. Thank you very much for your help.
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Harry Osborn – Written evidence (REI0035) Introduction The three interconnected requirements for the electricity industry stated are security, affordability, and decarbonisation and quoted as a trilemma. Decarbonisation is not a requirement to produce electricity. If this were eliminated from the equation the other two would not be a problem, and can be provided for. The production of electric power requires the use of fuel that is controllable in quantity and supply to satisfy and regulate the demand which is variable. Renewable sources cannot be controlled by man, and therefore cannot be used efficiency and provide for demand. Fuels all have a varying calorific value to provide the heat source of power generation, and all produce carbon dioxide except nuclear fuels. After the discharge of gas to the atmosphere the natural carbon cycle thereafter converts the gas to its original parts of carbon and oxygen. This is very efficient in the decarbonisation of the atmosphere. The fluctuations in this process can be recorded in parts per million at various locations. The Natural Carbon Cycle This is the natural process of decarbonisation of the atmosphere. Atmospheric CO2 combines with water vapour to form carbonic acid CHO3 and by weather changes affects the growth of vegetable and animal life, and is captured in ice. Carbonic acid is weak acid and falls mainly on the sea producing approximately 28 mg/l. This carbon level is maintained and by photosynthesis releases oxygen back into the atmosphere. This process is repeated on land areas which is only 30% of the earth’s surface. Security of Supply of Electricity To ensure the security of supply it is necessary to have generating plants that are available and capable of supplying power according to the demand. Plants must be capable of providing immediate power in surges of demand and can be shut down when demand ceases. Affordability To ensure affordability it is necessary to have power plants that are low cost in construction and can be operated on low cost fuel. Affordability is also related to the installed capacity which produces the power at a high percentage of that installed capacity. Power produced by coal fired, gas, and nuclear is of the order of 2p/kwh compared with wind turbines which produce power costing at a minimum of 9p/kwh. Local Power Generation and District Heating
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Local power generation is important in order to minimise transmission losses. A large amount of municipal and industrial waste is produced and disposed of in landfill sites and producing methane. Many of these sites are now full and these deposits represent a future source of energy. Municipal waste has a reasonable calorific value midway between coal and biomass, and could be used in plants in local conurbations. High pressure steam generated initially would be used to produce electricity, thereafter the residual low pressure would be used to provide hot water for district heating. Lerwick in the Shetland Islands operates a district heating system using municipal waste. The CO2 released will contribute to the carbon cycle, and produce biomass in various forms, and will maintain this important cycle. Energy versus Climate Change (CO2) The Department of Energy and Climate Change should be split. A separate Department of Energy would have the responsibility of searching and sponsoring the production of electricity that is secure and affordable. A Department of Climate should produce evidence on a scientific basis the causes of any changes to climate. If CO2 is the catalysis the rise and fall should be regularly recorded and announced. New power plants are required urgently to maintain security. It is estimated that the risk to security by 2030 is 60%. Industry will not be maintained or growth achieved at the present high cost of electric power. 3 September 2014
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OVO Energy, E.ON UK and EDF Energy – Oral evidence (QQ 29-43)
Evidence Session No. 3 Heard in Public Questions 29 - 43
TUESDAY 28 OCTOBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Hilton of Eggardon Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Lord Wade of Chorlton Lord Willis of Knaresborough Lord Winston ________________
Examination of Witnesses
Guy Newey, Head of Policy, OVO Energy, Dr Laurence Barrett, Strategy Project Manager, E.ON UK, and Paul Spence, Director of Strategy and Corporate Affairs, EDF Energy
Q29 The Chairman: Welcome, gentlemen. We are very pleased that you have been able to help us with our inquiry on the resilience of electricity and its supply. Before we start, would you like to introduce yourselves and if any of you would like to make an opening statement please feel free to do so.
Guy Newey: I am Guy Newey. I am head of policy at OVO Energy. OVO Energy is a supply-only business, so we do not have generation assets as such and we tend to see some of these issues from the other end of the wire perspective, but they are obviously of concern to our customers. In general terms, we have quite a lot of concern about the direction of energy policy, and generation policy in particular, and I am sure we will get into the detail of that in terms of costs and other matters that are relevant to this inquiry about resilience and reliability. OVO has 400,000 customers, which is up from around 120,000 about a year ago, so we are growing very quickly, which is probably indicative of some of the changes going on in the energy market at the moment.
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Paul Spence: I am Paul Spence. I am director of strategy and corporate affairs for EDF Energy. As you probably know, we are the largest generator of electricity in the UK, producing it from our mix of nuclear, coal, gas and renewable stations. We also, like OVO, are a supply company as well, supplying 6 million customer accounts. We are the largest supplier to industry and the fourth of the six large suppliers to domestic consumers.
You are probably also aware that as well as investing in the operation of the existing stations we have plans to invest heavily in four new nuclear power plants: two at Hinkley Point in Somerset and two at Sizewell in Suffolk. We are very aware that what we provide from our power stations is a commodity that is absolutely essential, more so than perhaps it was in the 1970s as part of the running of our economy. We are also dealing with an increasingly complex network and system, with the increasing amounts of renewables and intermittent renewables on the system. We are absolutely convinced that we need large companies able to take the long-term view and able to think across the operation of that whole system.
I should mention one other thing to the Committee. You will be aware that a number of our stations are off at the moment. Some of those are off for planned refuelling but four reactors are off at the moment. Those were a result of an issue we found with one of the eight boilers in one reactor at Heysham power station. We have taken off three other reactors of the same design in order to inspect them and see if we had the same issue in the boilers of those other reactors. Those inspections are going very well. We are about three-quarters of the way through and recently we updated the remit system to notify National Grid that we could maintain our expectation of a return to service between October and December of this year for all of the reactors. We expect to return three of the reactors at slightly reduced power in the first instance. That allows us to reduce the temperature in the boilers, which will then allow us to be confident that the mechanism that created the crack could not occur in those three reactors. Then we will look to increase power over the course of 2015 as we, if necessary, make modifications to those reactors.
Dr Laurence Barrett: I am Laurence Barrett. I work for E.ON UK. We are another major generator and supplier here in the UK. I am an upstream strategy project manager and I very much focus on the strategic impact of various policies and the market on E.ON and the industry as a whole. In the last few years, I have had quite a large involvement in E.ON’s response to the electricity market reform, for example.
Q30 The Chairman: Thank you very much. We will start by asking about your views on the capacity margin. We have heard today from National Grid, which has published this winter’s outlook for gas and electricity. The bottom line is that this year’s electricity margins have decreased compared to recent years, with the average cold spell margin expected to be 4.1%. Would you like to comment on this and say to what extent you feel that unexpected events or more outages—such as Mr Spence has referred to—might drive us into any difficulty or not?
Paul Spence: Perhaps I can start. I think National Grid, as part of its outlook, has said that it believes that the situation is manageable and it has used the mechanisms that it has in place through the supplemental balancing reserve and demand-side response to procure extra flexibility to protect the system. It is true that the plants on the UK system are ageing and that we need investment in new capacity. It is also true that we have a range of tools available to National Grid for the short term and for the longer term in order to make sure that we maintain sufficient supply on the system.
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Dr Laurence Barrett: It is also important to put the reports in context. Although the 4.1% de-rated margin that National Grid talks about appears very tight compared to recent years, we have been through periods in our history with similar de-rated margins in the early 2000s, and the system was reliable and resilient at that time. It is also worth noting that there are a number of other functions that National Grid can call upon in terms of its existing services—the supplemental balancing reserve and demand-side balancing reserve that Paul talked about. Beyond that, the 4.1% is within the Reliability Standard that the Government have set for security of supply within the UK going forward; it is actually well under it. We believe that while margins are tighter than they have been in the last few years the system should be resilient. We do not foresee any problems this winter and we expect that National Grid will be able to manage the system in a forthright manner.
The Chairman: Would you like to comment on the outages in your own organisation?
Dr Laurence Barrett: The only outage that we have had is at Ironbridge. Some months ago we had a fire at one of the units at Ironbridge, which was in the process of converting to biomass to allow it to run out until the end of 2015. Both units have to close due to the large combustion plant directive, so due to environmental EU legislation. The result of that is that one unit is not returning to service but the other unit has and is operating until the end of 2015. Across the rest of our fleet, we maintain that we respond to the signals within the market, both in the longer term but also on the balancing market as well in order to ensure that we are delivering all we can.
Q31 Lord O’Neill of Clackmannan: Mr Spence, you are employed by a French organisation, which fulfils a slightly larger role in France in terms of electricity supply. Could you tell us what the margins are in France as against the UK? We are talking 4.1 and 2.5 or so is the de minimis. Can you give us any indication of what another country that we are associated with has to operate within?
Paul Spence: Lord O’Neill, I would need to come back to you with the precise margin of supply over demand in France today, or over this winter, but what I do know is that the reliability standard set for the UK is the same as the reliability standard set for France. I know there is more capacity in France today, some of which is then exported to its neighbours, but in terms of the standard that the grid operates to, we are aiming for the same.
Lord Dixon-Smith: I can understand the context of a 4.1% margin in normal seasons but in my book, as a farmer, there is no such thing as a normal season. The season that frankly worries me is the freak one, where the weather is quite capable of doing something far more damaging than 4.1%. Should we be as confident as we are? I accept the statistical average but what I am worried about is that that average is made up occasionally of some extreme events.
Guy Newey: That is always going to be the case in any system. The question is how much cost are you prepared to pay to have that 99.6%, 99.8% or whatever pushing it up? It is that extra cost that is the issue and that is why I think the historical examples are important, because what you would expect in the market over a cycle of 10, 15 years is that when things get tight, that provides a signal to invest in the market. That is certainly what we had in 2005-06, when we got down to about 5% or 5.1%. What happened afterwards is the market signal worked, we had a mini dash for gas and people went out and built lots of CCGTs, which gave us a bit more comfort. In fact, they probably built a few too many CCGTs.
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The question now is whether an intermittent higher system is more vulnerable and whether you are getting the signal going forward.
But there is another point to make. There is no strong signal in the market, for example, to build new CCGTs, gas-fired power stations, at the moment. There are lots of potential reasons for that and I do not think anyone has a definitive answer but one of them might be that peak demand in the UK is falling. It has been falling since 2005. Some of that is due to the recession but some of that is just due to our having got a bit better at managing peaks in terms of energy efficiency, as well as changes in the UK industrial pattern.
Lord Dixon-Smith: May I just follow that slightly? My concern is whether you have the mechanisms and the capacity to manage demand, because in the end that is going to become an increasingly critical factor. I am not sure whether at the moment the mechanisms are in place to make managing demand in a serious way play a role that in future is going to be—
Guy Newey: From OVO’s point of view, we have a reasonable level of confidence in the systems that National Grid and others have set up to deal with short-term imbalances. There is a lot of potential in terms of demand-side management and we think—we are as confident as we can be at this stage—that it will not lead to the kind of interruptions that we saw in the early 1970s.
Q32 Lord Broers: I would like to follow up a bit on these nuclear plants, Mr Spence. Could you tell us a little more about how long it would take you to replace this boiler spine, if it turned out to be faulty, and whether it would need redesign? What are we talking about here? First of all, with the plant that has the problem and then how it would ricochet on. How long will it take to fix this problem?
Paul Spence: I can start by just explaining what we have found in the one of the eight boilers where we have found a defect that has turned into a crack. Essentially there was an original defect and then, because of the temperature this part of the boiler operates at, we have seen that crack grow. What we have been looking at is whether—
Lord Broers: Sorry to interrupt, but is there an actual leak at this crack?
Paul Spence: There is not a leak. This is not within any of the nuclear components. This is strictly the boiler associated with it. The first thing is that we have seen that crack grow. Our safety cases do allow for having such a crack, but we are looking to make sure we can satisfy ourselves that there is not a similar circumstance in the other seven within that one reactor and then within the same boilers on the others. As I said, we have been through an inspection using a mix of visual inspection and radiographic techniques, and we are three-quarters of the way through that inspection of the other boilers on the other reactors. We have not found any cracks in those others, so in that case the question of whether we need to do something about it is essentially moot. We do not need to look at repairs. We are making sure that we have a way of continuing to check that there is nothing to repair.
At the moment we have techniques to isolate the one boiler where we have this issue, so we can operate the reactor without that boiler being needed, which is what we did before we took it off for this inspection and what we are talking to the regulator about continuing to do. Then we will look with our engineering team at whether there is a way, and what that way is, perhaps to repair the one cracked boiler spine.
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This only affects two of our stations—the first unit at Heysham and the unit at Hartlepool—because they were built as sister stations to a particular design. It is not something that affects any of the other of our fleet.
Lord Broers: If you could disconnect this one from the system, why have you shut down the plant?
Paul Spence: Having found the crack we wanted to make sure that we understood what the conditions had been that created that crack and whether or not it replicated elsewhere.
Q33 Lord Willis of Knaresborough: I am a little cynical here because when everybody seems to be coalescing around something that says it will work and it is good, I always look for the worst scenario situation. Lord Dixon-Smith mentioned the problems with weather. Imagine if we did not have these cracks in the summer period, when there is plenty of excess capacity over demand, but had it, for example, in 2013 when Northern Ireland suddenly was closed down because of extreme weather. If we had to take nuclear power stations offline then, we would be in a position where these whole new balancing services, which all of you have talked about as being the saviour, would come into operation. How resilient do you think the balancing proposals are, which you have all talked about as being our saviour? Are they good enough to take us through the real extremes, which we might get in unforeseen circumstances? You seem a bit complacent to me, if you do not mind me saying.
Dr Laurence Barrett: We are not complacent. We are definitely ensuring that our stations are available to aid in that resilience of the network. The two new services that National Grid have procured are only one part of the solution, and there are also existing services. We have interconnection. The de-rated margin means that you have a much greater amount of capacity on the system. The de-rated margin tries to take into account the fact that you might get breakdowns. So we have over 60, 65 gigawatts of plant on the system to meet that peak demand.
The other element is the de-rated margin takes into account, to a certain extent, weather effects, so it talks about average cold spell and adjusted demand. It does not go to the extremes of very unlikely weather effects but, coming back to Guy’s point, you have to find a balance as to whether you insulate your system against every conceivable outcome, because if you try you will not succeed. So you have to find a balance with the cost of ensuring that resilience.
To come back to your key question, about how resilient these new services are, they are not asking those providers to do anything that they cannot do. For example, the supplemental balancing reserve is asking those providers to be available through winter weekdays. That is what generation plant do day in, day out. This service is giving a different economic signal for when that provision is required but it is just doing what a generator does, so I do not think we should have any worries about its ability and capability to deliver.
It is the same on the demand side. We have a demand-side response. We have it in a number of other functions active already in the market, so we are just asking those demand side providers to do services that they can normally do. It is the way they have been procured that has changed.
Q34 Lord Willis of Knaresborough: Thank you for that, Dr Barrett, but both the demand side and the supplemental balancing reserve depend on somebody paying you or customers
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for not using electricity or for bringing that supplement on board. That is the taxpayer, I presume, so you cannot lose, can you, on this?
Dr Laurence Barrett: When a generator generates or a demand side reduces demand, they are always being paid to provide that service, whether it is through the normal electricity market and contracting from a generator to supplier, through the existing balancing services or through the new services that National Grid has. If you are asking generators to generate more to ensure that supply is matching demand then, yes, they are being paid for that service. The new services are a different mechanism for paying that but it is not an unreasonable part of the functioning market.
Guy Newey: You have a choice. You can either pay for an extra power station, you can pay someone to come on for the extreme winter nightmare scenario or you can pay somebody and say, “If this happens we will give you a cheaper price for your electricity for the rest of the year if you turn off for these couple of hours”. It is an economic choice. At the moment paying somebody to turn off is a cheaper option than buying in the new power station. It is just a case of how you balance those things. But that is something very different from cutting off a group of customers.
Paul Spence: If I may, I will go back to your question about complacency. We have talked a lot about the new mechanisms that National Grid has to manage this piece. As a generator my observation would be that the starting point is about making sure that we invest in maintaining the reliability of the plant that is already on the system, to make sure that the allowances that are made for the de-rating are conservative as well.
I know that my company has been investing over £1 billion each year looking after our nuclear stations and our coal stations, but also building a new combined site or gas station to be on the system and investing in renewables. So it would be unfair to talk about complacency. We know we need to invest in the existing system. We know the grid needs some short-term tools in order to manage through this period that we saw coming. Then we need investment in new generating capacity, which is what the electricity market reform arrangements—
Lord Willis of Knaresborough: But you have said in your evidence that this short-term fix basically prevents you making more long-term decisions, which prevent those short-term fixes, or have I misread your evidence?
Paul Spence: I need to go back and relook at our evidence because that is certainly not—
Lord Willis of Knaresborough: You have said, “We believe these measures can make an important contribution but they will not bring forward the investment needed to ensure security of supply over the longer term”.
Paul Spence: Over the longer term the measures that will bring forward that security of supply are the electricity market reform arrangements, so the contract for difference arrangement that we have recently concluded with the UK—we concluded it last year with the Government and got approval for Hinkley Point C—is an example of the arrangements that will make sure that there is investment in new capacity. The capacity auctions that we will see this winter are the way that we will make sure that there is efficient purchase of the medium-term capacity that we need. What we have here with the supplemental balancing reserve and with the demand-side response is a tool for National Grid to tune in the short term and make sure that things happen. It is a coherent package of arrangements that are
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designed to have the system managed through in a way that affordably delivers the right standard of security of supply.
Lord Willis of Knaresborough: But it maintains a high price to the consumer, does it not?
Paul Spence: It is done in the most affordable—
Lord Willis of Knaresborough: It is more than you are charging your customers in France.
Paul Spence: The cost of electricity in the UK is above the cost in France, that is true. France made some choices in the 1970s and 1980s about their generation mix and chose a nuclear mix, which has delivered reliable low-cost electricity for them. Here in the UK we have a different mix. We have less interconnection to France and we have seen the costs of electricity, in particular, driven up by the cost of fossil fuels over the course of the last decade, and we also now need to renew that system. That is the whole premise behind the electricity market reform arrangements.
Q35 Lord Rees of Ludlow: I would like to go back to the issue of the extreme events. Obviously your companies respond to market pressure and that depends on the insurance premium which the Government are prepared to pay for the one in 50 year event. Do you think that the incentives that you were given are sufficient to reassure the public who probably rarely care about the risk of catastrophe, even if it is a one in 50 year chance?
Dr Laurence Barrett: The basis of the decision on how much capacity to procure has come back through what is termed as value of lost load. So this tries to look at the value to the customer of having a service of electricity provision or not. It is an extremely complex calculation. It is different for every customer, varies depending on the time of year and varies through time itself. But it tries to find the appropriate balance between the cost of providing new capacity and the cost of not having that capacity and associated power cuts.
As we have talked about, that has generated our reliability standard of three hours of loss of load expectation. That is not three hours of customer disconnections. That is three hours where National Grid has to take extra actions beyond the normal market actions, and there are numerous services it can provide. They can do voltage reduction and maximum generation. Also, let us not forget the level of interconnection we have. That three hours loss of load has been determined. We are comparable to France as a connected market, with the same reliability standard. If you look slightly more broadly to other interconnecting markets, our reliability standard is more reliable.
The balance we have is consistent with the international standard out there for how reliable an electricity market needs to be. In the last few years, we have had a very high level of security of supply because of some of the aspects we talked about where the market responded, invested and then because of recession and reduction in peak demand, we ended up with a large amount of oversupply. It does feel consistent and it is the right balance between costs associated with providing capacity.
Lord Rees of Ludlow: It seems to me that we are all mindful of we are getting more vulnerable. We know the City of London could not survive for a day without electricity and so the downside risks—not just of bad weather but of some other problem with the grid—are potentially catastrophic, even if unlikely. I just wonder if the calculations take account of this change in the perception of extreme but catastrophic risks.
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Guy Newey: Ultimately the decision of how reliable you want the system to be is a political decision. Make no mistake, energy companies want to keep supplying energy to customers for quite obvious financial reasons but also because it is the right thing to do. The Government have ultimately got to decide whether they want to have a system that is resilient to a one in eight year, a one in 100 or a one in 200. The more resilient you make the system the more expensive you make the system and the more gold-plating you have. You will never be able to completely remove risk of course, but that ultimately is a political decision about balancing costs overall to a system and the ability of bill payers and taxpayers to match those.
Paul Spence: Just to echo Guy’s point, it is a choice. I said in my opening remarks we—and I think all of us—are very conscious of just quite how critical electricity is to our customers and to the UK economy.
Lord Peston: Just to clarify: you are all three firms in the private sector? You are not social services?
Guy Newey: No.
Lord Peston: But the Government poke their nose in to get a social service element in by subsiding you to install more capacity than if you were simply paying attention to the interests of your shareholders. Did I get that right? That is what Professor Newey seemed to be saying categorically. You gave a very good analysis of the nature of the decision. Speaking as someone who used to do operational research, I know about this stuff and the cost goes to infinity if we take inventories. If you are never going to run out of anything and you are never going to be short of capacity, again the cost goes to infinity. The Government must be getting you to do things you would not do if your only interests were your shareholders, although I am going to add a gloss to that in a moment.
Guy Newey: The market has a lot of intervention and an increasing amount of it. It is important to get the distinction right between the Government making us do something and the Government paying for it, and in the overall scheme of the energy system it is not direct government money. They tend to make customers subsidise bits of kit, particularly on the generation side. Hopefully that provides some clarity.
Paul Spence: I am not sure I quite recognise your description of how things operate. At the heart of the UK energy system we have an energy-only wholesale market, which is the traded market. It pays a price for the short-run marginal cost of the electricity that we are producing and, at periods of tightness, sends a signal that you should build some more.
The Government and Ofgem have judged that allowing the market free rein may mean that too little gets built too late and so they have added on a component, which is about paying to have the capacity margin that the Government judge is required in order to make sure that we do not face blackouts before companies act and invest. That is a judgment about creating the most efficient market to make sure we have both energy supply and spare capacity available. They are the market rules that we operate within as private companies.
Lord Peston: As you know, since you know some economics, none of the great economic theorists have recognised what you have described as a free market, but that is by the way. I am not saying it is wrong, I am simply saying that their concept of a free market is slightly different. You are EDF, which is what we have in our house, and we are very happy.
Paul Spence: I am delighted to hear that.
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Q36 Lord Peston: As another dimension to this, are there any reputational advantages to you by not being the supplier who fails to deliver? In other words, is there a further hidden benefit to you in that your shareholders want you to do something just because they want to be shareholders in a firm that does its job properly?
Paul Spence: I will talk for EDF, I am sure these guys will talk for their companies. I talked at the start about the fact that we are a large company that needs to take a long-term view. We do research and development about the evolution of the industry precisely because we know that what we want to do is to deliver what our customers need and want over time and all the time. I am very clear, I do not want there to be a shortage that means I cannot supply my customers what they ask of me. That is part of what I need to be in a position to do. But at the same time, as you said, I need to return a fair return to my shareholders and I need to charge for my customers a fair price for that, so it is about getting that balance right, operating in the market that the Government and the regulators designed for me.
The Chairman: We need to move on. I am sorry, I have a lot of people that want to come in. Lord Patel, if we can move on to your next one.
Q37 Lord Patel: My questions are mostly related to the capacity market. The key one being the role of the capacity market in balancing supply and demand. But the subset of that question is why we need a capacity market. Why can the wholesale market in electricity not deliver sufficient capacity? If we have too much capacity, will that not just result in higher costs for consumers? Can it not be a ploy for the companies on one hand to ask for more from the capacity market but at the same time mothball some of the gas plants to put further pressure on the Government?
Guy Newey: We remain pretty sceptical of the need for a capacity mechanism. As I said before, historically the market signal has been able to provide the signal for new generation. There is an open question about whether you have a heavily interventionist government policy making decisions all over the place that you need yet more intervention, but the question is whether you try to roll back that intervention or intervene anymore. It seems very odd that we are providing a subsidy to coal-fired power stations on the one hand and at the same time spending a lot of money trying to reduce carbon emissions on the other hand. Reducing carbon emissions is a very sensible aim but doing it by keeping coal power stations running seems extremely odd.
The effect of a capacity mechanism will be to add cost but that is back to that political choice about what price you want to pay for extra capacity, and the Government have decided that they think customers are willing to pay. It dampens—
Lord Patel: Sorry to interrupt, but presumably it is because the companies probably told the Government that they cannot guarantee meeting the capacity to the wholesale market.
Guy Newey: That is certainly the argument that has been put forward.
Lord Patel: Is it a correct argument?
Guy Newey: I question it. We look at it from a supply-only market; we are not building new generation. If you are making an investment, it is certainly advantageous to have the certainty that a capacity market adds, but that adds extra cost to the customer and it is a question of whether that is fair. The other disadvantage is the capacity mechanism dampens market signals. If you are an interconnector coming over with cheap electricity from Europe
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and you are thinking of buying something, you make some of your money at times of peak demand in the UK—the price goes up so it is advantageous to do it. That is part of your business case for building it. Capacity mechanism dampens that signal. It says, “Actually it is going to be a bit flatter so you are not going to be able to make that money”. Is that advantageous? Do we want all of our energy coming from within the United Kingdom? Again, that is a political choice but the overall effect is likely to be that it will add costs for customers.
Lord Patel: So whose policy is wrong: the regulator’s or the Government’s?
Guy Newey: The capacity mechanism is a government policy. It is important to put it in the wider context of where energy policy has been heading, which is intervention after intervention after intervention, and towards a much more planned generation system. I suspect that your next witness will talk about this in more detail.
If you move to a situation where the Government are deciding prices on every particular technology—whether it is offshore wind, onshore wind or nuclear power and so on—eventually you are going to have to give everyone a set price, so you make all the decisions in the market. That might give you a very reliable system but it might mean that you are also paying for a lot more generation capacity than you need to.
Dr Laurence Barrett: We also need to put this in context. We have talked very much about cost and security of supply. There is another facet to the policy direction, which is decarbonisation. That increases the complexity an order of magnitude. It is not just about looking at two items, which is difficult enough, it is that third one which interacts with those. The capacity mechanism is one of the policies introduced under the electricity market reform to help drive along policies through all of those elements: decarbonisation, affordability and security of supply. As a suite of policies it has the potential to deliver on all of those.
It is an intervention from the Government but it is an intervention that produces a market-led result. For example, contracts for difference could be very specific that each individual plant gets a price, but the main mechanism for contracts for difference is a competitive, market process. The long-term aim for that is to be technology neutral, such that all those technologies are competing on an equal basis. We believe that those market-led approaches are going to give you enough flexibility to respond to the almost inevitable changes that we are going to get as we go forward over the next 10, 20 years. But it also gives enough signal for investment to come forward.
The capacity mechanism is the same. It is a market-led mechanism. It is a competitive auction to procure capacity to ensure we have enough resource adequacy. It is done in a balanced way looking at the cost associated with that to try to find an equilibrium point, but it is a market-led approach and should therefore, we believe, deliver the best value for customers in terms of ensuring security of supply.
Q38 Viscount Ridley: Just to pick up on that last point and to come back to something Mr Newey said, it is very clear that we only need the capacity market mechanism because of decarbonisation. In a world in which decarbonisation was not a policy goal, we would find a different market mechanism to supply the resilience that we are after. For example, in such a world one would see much more gas being built at the moment because the gas price is going down, for example. Can you put a price on the degree to which we are buying
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resilience at the expense of affordability—to go back to a point that Lord Willis made—because of decarbonisation?
Paul Spence: Answering your second question first, I am not sure that there is a way to price the different elements of optimising a system which is about getting the most affordable, secure and low-carbon outcome. I have not seen analysis that allows you to deconstruct it in the way you ask.
As to your first point about whether we would still need a capacity mechanism if we did not care about the carbon intensity of what was being produced, I believe that we would. You have a market that is designed to clear supply and demand at a particular level, and the price is the signal that would do that. If we want insurance to make sure that there is excess capacity over and above what might be needed and to make sure the lights do not go out, then there needs to be some sort of a mechanism to make sure that that extra, over and above what the market would naturally build, happens. So there would be a need for some mechanism to achieve capacity, even if we were to put aside the decarbonisation element.
Viscount Ridley: Just to follow up on that, Mr Newey said it was an economic decision as to whether or not one goes for a supplemental balancing reserve, demand-side management or having extra power stations in the background. How much is that decision affected by the fact that renewables get priority on to the grid versus gas, for example?
Guy Newey: I am not sure that is right, in that renewables will tend to get on to the grid anyway because they have low marginal costs—when the wind blows they do not have to burn anything.
Viscount Ridley: But they would need to be subsidised to get to that.
Guy Newey: Yes, of course. That is the wider point. Obviously wind is being favoured in the sense that it is getting the wider subsidy. Back to the question of how much it is going to cost, the cost will be revealed when the auction is held later this year—the market will reveal its price for this amount of capacity. It is a market process but it is worth stressing that it is based on the Government deciding what they think demand is going to be in 2018, 2019 and going forward. Historically, Governments, or any kind of central bodies, have been pretty awful at that. If I can remember my history right, in 1970 the CEGB said that peak electricity demand in 1995 would be 100 gigawatts. It was about half of that. If we had built and contracted for 100 gigawatts we would have an extremely reliable system that was extremely expensive—which some might argue is where we ended up with the CEGB.
On your other point about capacity market and energy only market, I tend to be somebody who thinks that energy-only markets can work in terms of delivering security of supply. But there are plenty of examples of markets—this is nothing to do with climate change or carbon emissions—which have a capacity element. The Government have decided that it is worth having that extra bit of confidence and gold-plating because electricity is so central and that they are going to pay for it. It would probably be a consideration anyway, even if it was not climate change. It is an active debate. When privatisation first happened, we had a capacity element. Some people would argue that the emissions trading scheme was effectively a subsidy for power stations to keep open anyway. Paul’s point is right, you could design it any way. It is always a choice of how much are you willing to pay for that extra bit of kit.
Q39 Baroness Hilton of Eggardon: There was a brief mention of research and development and future technologies. Is there any prospect of electricity storage? We seem to have had
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conflicting evidence about electricity storage, which would overcome the intermittent quality of wind power, for instance. Do you see that as a viable option in the near future and do you think it would increase our resilience to various haphazard events which we have seen lately?
Dr Laurence Barrett: It does have the potential. Electricity storage on the scale that we might need to help the situation is in its infancy. It is in research and development. One of the elements of helping support that is to see if it can stand on its own two feet, to see if it can move down the path of cost reductions. It can benefit from advancements that are made in other industries, for example, the car industry, where they are looking at electrical vehicles. So there is potential in energy storage.
It is important to note that if you put that in the appropriate market framework and market-led framework, then once it has gone through that research and development period, where it has had support and funding to help develop it, it can then be seen whether it can compete on a like-for-like basis with the other forms of generation or demand-side management. Again, we are moving towards a technology-neutral response led by the market that sits within the framework that the Government have dictated. There is potential, but it is early days on energy storage.
Baroness Hilton of Eggardon: What about other future technologies? I think Mr Spence wanted to address that as well.
Paul Spence: All I was going to add to what Dr Barrett said was that we are members of the Energy Technologies Institute, which is working with Government on future systems evolution and on the different possible technologies. It is clear that there are some technologies out there that are hopes at the moment but are non-economic hopes. Those technologies include energy storage, more efficient solar photovoltaic technologies, biomass and smaller modular nuclear reactors. We are in transition in a system that is going to be about centralised generation as well as local generation, and we need research and development in all of those technologies from the sorts of companies that can do the future research but also then scale it up to large scale.
Baroness Hilton of Eggardon: But there are no short-term solutions to the current situation?
Paul Spence: I do not think anyone has found a magic bullet yet.
The Chairman: Lord Hennessy, do you want to come in on this one?
Q40 Lord Hennessy of Nympsfield: Can I ask a specific question of Paul Spence in terms of the technologies of civil nuclear power? Do you carry in your head, because it all rests on you—this one company—a list of “don’ts” from the tragic story of British civil nuclear power since 1945? Can you give us any feeling that this time round it is going to be the bonanza that I have been expecting since I read the Eagle comic in 1953?
Paul Spence: There are a lot of lessons to learn from British civil nuclear power and from global nuclear power. Rather than reeling off the list here and now I would be delighted to come back to you.
Lord Hennessy of Nympsfield: Give us the three highlights, the most important “don’ts”.
Paul Spence: The first I would say is that it is good to recognise that civil nuclear power is a global industry. You belong to and are part of that global industry in terms of the
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technologies you choose, the safety improvements that you adopt and the standardisation that can come from that—and therefore the cost—so there is one about not going off on your own path. There is a second about making sure that you have great people all the way through the company. There were some positives about what the UK civil nuclear industry did as it led the way, but there were also some areas where I think it lost sight of making sure it had people who were the best all the way through the world. There is a third one about making sure you can deliver what you promise. In my role in EDF Energy I rue what was said by the guy in the States about too cheap to meter.
Guy Newey: The big lesson for me on the British nuclear history is the danger of centralised planning and too few people—they were all men—making the decision about which particular technology to use. I am trying to remember the name of the Energy Minister at the time but when he announced the AGR project he said, “We have cracked it”. We then went off and followed that path for years and years, without—because it was a centralised system—anyone correcting it. We eventually spent I think £50 billion on our civil nuclear programme, which if it had been in the private sector would have been the biggest bankruptcy ever in the history of private business, because we did not have those correction processes.
The other argument is that we can just do what France does. They kind of did it quite well for some of the reasons that Paul indicated, but there are huge dangers. I know that in some of the evidence you have seen there has been a suggestion of the idea of a systems architect. Systems architects are just people making choices based on the information they are giving and without foresight going forward. But they may have the confidence that they have the foresight going forward, so they will say, “We have looked at everything and it turns out that tidal power or the EPR reactor is the right answer”; and off we go and spend a fortune on it.
Wherever you can get market processes and feedback going on, then we have a much better chance.
Paul Spence: If I may, just to add in defence of the civil nuclear industry, 20% or so of UK electricity today is being generated low-carbon and affordably from the nuclear power stations that are operating. It is not all a negative story. It is there, it is successful and it can be more successful in future.
The Chairman: We are getting near the end of this session. Lord Winston and Lord Broers wanted to come in, and then Lord Ridley has another question.
Lord Winston: Just a very brief question in view of time. I declare an interest as professor of science and society at Imperial College London. Paul Spence, could you just outline what you are doing about public engagement with regard to the cracks in your boilers? It would be quite helpful to hear how you are dealing with that issue.
Paul Spence: First of all, we have been very careful to communicate ourselves. We have obligations under the remit arrangements in terms of just telling people what they can expect from the system, but over and above that we have been doing work to communicate the science of what is going on. We have been working with universities like Imperial and Bristol to help us with that, and we are also working with the Science Media Centre to help us brief journalists and the media on exactly what is going on, what we are doing about it and—another plug for British engineering—the quality of the people who are working to
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find solutions to problems that people did not think about in the 1970s, such as how you inspect these components down a gap that is less than a centimetre, some 12 metres below you. You need to have brilliant scientists and engineers to be able to get in there and find out what is going on, and then work out ways to innovatively solve those problems. We are trying to communicate all of those things.
Q41 Lord Wade of Chorlton: You have described a very complicated industry so far to me, and I find it more and more difficult to understand how it is structured. What I would like to know within this very complicated system is, if the lights do go out and the City of London does not get any power, whose fault is it? Where does the responsibility ultimately lie? What can you do to make sure it never goes out? How reliant are you upon a government action or somebody else’s action to make sure they never go out? I want to know who ultimately would take the responsibility or who you would point to if the lights did go out.
Dr Laurence Barrett: If the lights go out no one wins, so I do not think you necessarily need to point the finger at any particular organisation. The Government are not going to come off well, energy suppliers are not going to come off well and National Grid—who have the responsibility of balancing the system—are not going to come off well. It is in everyone’s interest to try to ensure that we are doing the right things right for our customers, and one of those elements is delivering energy and electricity as and when they need it. We are not complacent about it.
Lord Wade of Chorlton: At the right price.
Dr Laurence Barrett: At the right price, yes. As we have talked about, there is a trade-off: there is always a trade-off between cost and delivering that security. We are all doing whatever we can in order to ensure that that does not happen, through National Grid’s new services and through investment in our plant, be that thermal, renewables et cetera. No one wants to see that happen and we believe that we are in a position where we will not see that happen.
Q42 Lord Broers: Can you give us a rough estimate of how much cheaper electricity is in France? Would you like to comment on whether you think the French nuclear plants would meet today’s safety standards, which we are applying to the new plant?
Paul Spence: Rather than making up the percentage that France’s power costs for domestic or industrial consumers are below the UK’s, I would like to write to you with the precise number on that. In terms of the safety of the technologies, we have been through a process for the station that we propose to build at Hinkley Point over the last five years with the Office for Nuclear Regulation here in the UK to get design acceptance for the EPR design. That is a design that is being built in Flamanville in France and it meets the safety standards here in the UK. It has learnt and built on the lessons of the last three or four decades of nuclear operations and it is also built on the lessons of Fukushima. That is the station that meets the current safety standards.
Lord Broers: They would be considerably stricter than the plants that have been running for decades there, I assume.
Paul Spence: We have this principle with safety standards that the risks are as low as reasonably practicable. The plants that were built have had safety enhancements over their lives as well. We spent £180 million across the UK nuclear fleet in the wake of Fukushima to
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install some flood protection and other improvements, learning the lessons of Fukushima. The safety expectations and the technologies have evolved and will continue to evolve.
Lord O’Neill of Clackmannan: How much over budget is Flamanville and how much more expensive would an EPR be to run than the other nuclear plants that it is now envisaged being constructed in the UK? Is it not the case that both the Finnish and French examples have been disasters in construction terms, safety notwithstanding, and that the running costs of these plants will be very high, to take account of the very high capital expenditure that has been incurred in the construction errors that Areva and others have been responsible for?
Paul Spence: It is true that neither of the projects at Olkiluoto in Finland or Flamanville in France are examples of what we want to see here at Hinkley Point. We have learnt a lot of lessons as a result of that and have built those lessons on how to do a project and how to do a project well. We have also learnt the lessons of the Olympics and have a stable design that has been approved by the regulator. We have had the team that will be involved in construction involved early. We are using new technologies, including 4D technology, to plan the construction. We have what we believe is a world-class team of people who will build it here in the UK. That is all designed to make sure that we have a successful project.
Lord O’Neill of Clackmannan: Did you not think that you had that in Finland and in France when you started these two projects?
Paul Spence: It is not for me to comment on what the Finns had in place; that was not a project that EDF was involved in.
The Chairman: I am going to ask Lord Ridley to ask the last question because we are running seriously out of time.
Q43 Viscount Ridley: I think, Chairman, I can be very brief because Mr Newey has given a very eloquent answer to my question already, which is whether or not we are going down much too much of a central planning route. The suggestion that the Institution of Engineering and Technology gave us that there should be a tsar who runs this, called a systems architect, is not a great idea, so unless the other two of you want to disagree with that non-endorsement of that idea, I will leave it at that.
The Chairman: Would any of you see a role for a systems architect?
Paul Spence: I think we already have three bodies: the Department of Energy and Climate Change, Ofgem and National Grid, all of whom have responsibility for looking across the system as a whole. You also have companies like mine that look across the system as a whole and try to form a view about what it needs and what it is going to look like. Personally, I am certainly not convinced that we need more beyond that.
Lord Peston: Chairman, I do not have a question, but when you provide the data to Lord Broers on the relative costs of electricity I take it you will allow for the sterling/euro exchange rate because the reason is the pound is too strong, of course.
The Chairman: I will just make one point, which is please do not send the information to Lord Broers, send to our clerk and then we will all get it.
Paul Spence: Of course.
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The Chairman: I am grateful to you for having assured us that you will write to us on those specific matters on the cost in France. I think there was another matter we mentioned earlier. We have run out of time. I am most grateful to the three of you for having given us some very helpful evidence. You will have an opportunity to read the written record and if there is any alteration which is needed as a matter of fact, you will have an opportunity to do that. Thank you very much for joining us today.
PCAH (Parents Concerned about Hinkley) – Written evidence (REI0002)
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PCAH (Parents Concerned about Hinkley) – Written evidence (REI0002) We are interested in the following questions: Short term (to 2020) How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base? What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’? Install onshore wind and solar on all UK coastal nuclear sites where the land is too radioactive for any other development. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? Impossible to say how nuclear can still be promoted by government when there are endless financial and health detriment costs and absolutely no benefits except those conferred by UK taxpayers on foreign companies who can maximise their profits and then leave the UK with waste, decommissioning, spent fuel and health detriment costs ad infinitum and that’s thousands of years and counting. What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? Make planning approval for onshore wind and solar the national default. Rule out new nuclear build. Shut down all carbon intensive AGR nuclear reactors; cancel lifetime extensions. Promote community funded small grid onshore and solar development. Support solar installation and electricity storage by industrial estates, local authority buildings, NHS hospitals. Utilise radiation contaminated land on all UK coastal nuclear sites for solar and onshore development. Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure? The insights are already available, government needs to take advice from experts in renewable electricity provision. Medium term (to 2030) What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience? Resilience will be achieved by linking into the European smart grid. What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information
PCAH (Parents Concerned about Hinkley) – Written evidence (REI0002)
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is needed to improve models? By 2030 offshore wind, hydro, wave and tidal will enable the UK to become self-sufficient in electricity production, supply and resilience – start with the Severn Barrage. Remain linked into the European Smart Grid. What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? The current policy of promoting new nuclear is insupportable. It would be the most expensive, most dangerous, most inflexible and least resilient. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? The technology is ready and available as demonstrated by Germany, Italy, Switzerland and the Netherlands. Wind, wave, tidal, solar and hydro electricity emit low greenhouse gases during production, hardly any at all during operation. Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system? The most important decision is to rule out new nuclear, shut down existing AGRs, enforce safety priority for nuclear decommissioning and waste policies Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects? Yes, the measures are in place – learn from what Germany’s doing. Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? No, current regulatory and policy context in the UK favour nuclear and disadvantage renewables. A long term market led approach would achieve resilience by 2030. How do you define ‘market-led’? Does it mean subsidising new nuclear at huge cost to the taxpayer while denying support to renewables? That is what current UK policy is proposing and it must be changed to ruling out nuclear and supporting renewables. 25 July 2014
Marco Pogliano – Written evidence (REI0008)
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Marco Pogliano – Written evidence (REI0008) I want to answer about the inquiry of how resilient the UK’s electricity generation, transmission and distribution infrastructure is to sudden, unexpected events such as severe weather, power station failure or cyber attack, if resilience will be affected in the medium term as electricity generation is decarbonised and becomes more distributed, and the impact of new demands such as electric vehicles and smart appliances giving consumers more control over their electricity use. At first we must consider that the best way is to build mini power stations distributed all around the Nation in addiction to the power stations that actually are working. We need to turn to the power generation from fossil fuel to green energy. The photovoltaic systems, the production of hot water with solar panels and the wind turbines, are not power generations that in the long term can substitute the fossil fuels. In fact sun and wind are not availables 24 hours per day, and neither for 365 days per year. We must also consider that photovoltaic panels, solar panels and wind turbines are very expensives and the time to amortize the investment is long. Therefore it would be appropriate not to have significant differences in production alongside photovoltaic system. Other types of generators always operate with renewable energy sources. I propose the woody biomass. The generators I am proposing work well with the wood and with waste of agricultural crops such as corn too. There are fast-growing plants, which is not weed, that allows you to make the first cut after only two years in the varieties for biomass. There is another variety also suitable for construction that allows the first technician cut after only one year and the next every three years. These data is referred to Europe. The CO2 abatement achieved by reforestation with fast-growing plants, as well as create new jobs in the agricultural sector, is of strategic importance to the world. From the combustion of the wood is possible to obtain hot water and electrical energy with low costs. Nowadays it’s possible to obtain the necessary wood from plantations of fast-growing trees. From the trunk of the tree we get pellet, that burn inside the boiler. In the last few years a new method to use trigeneration is coming out, thanks to pyrogasification. It also uses biomass and reduces the emission of carbon dioxide into the atmosphere.
Marco Pogliano – Written evidence (REI0008)
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By using biomass we have a constant production of electric current and hot water for 24 hours per day and 365 days per year, regardless of ambient conditions or the presence of traditional energy sources. We use electricity generation for lighting, for electrical appliances, for heating, for industry, for electrical vehicles. We can use biomass generation to produce energy for electricity, for heating, for domestic hot water. Every building can have biomass generation to produce its own energy requirements and can sell at low cost the surplus production to the National grid. This is an advantage for the UK’s electricity system, because the UK can increase its electricity system with low costs. There are other ways to reduce the energy requirements in addition with the biomass generation:
Thermal insulation panels
We can use panels based on lime and hemp for internal and external walls, loose insulation based on lime and hemp for cavity for internal and external walls, insulating plaster based on lime and hemp for internal and external walls.
Glasses with high thermal insulation
Underfloor heating
Thermal insulation of the floor and of the roof
Led lamps In short we can use biomass generation, thermal insulation panels, glasses with high thermal insulation, underfloor heating, thermal insulation of the floor and of the roof, led lamps all together or only one of them or a mix of them too. These methods can be applied in new building or restructuring buildings, but also in existing buildings. Conclusions The UK government can provide incentives to people to encourage them to make the most possible to reduce the energy consumed . This policy will help the UK to the achievement to have most of the energy produced from renewable sources, without incurring large investments, in the short term. For example, 1 MW of power mean 200 units of 5 kW, if the surplus production of each site is fed into the national grid, you get many benefits: 1) Investment by the government minimum, only the incentives. 2) Speed and capillarity of accomplishments.
Marco Pogliano – Written evidence (REI0008)
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3) Lower maintenance costs only to the distribution network, surely if the incentives are bound by an oversizing of the plants. 4) The Government may purchase the energy produced by individuals at a lower cost of the sale price to the same. 5) Ability to hijack the state of energy production in areas where it is not possible to install by private individuals, or to industrial zones. These considerations are to be assessed for the beginning of the first results in the short term.
The UK government will have a positive image all over the world, as one of the most sensitive in the world; the aspiration to have a low environmental impact of energy production, and sensitive to the welfare of its inhabitants.
With proper reforestation policy, the UK get low-cost fuels, re-creating green space required by the Kyoto Protocol, with the undoubted benefits.
The UK government will expand foreign industries, which will obviously be attracted by the possibility of having energy at competitive costs.
I am a professional consultant in close cooperation with well-known companies. I conduct part of my business as consultant to the energy savings, in cooperation with other two consultants. I hope to have sparked a real interest explaining how the UK’s electricity generation, transmission and distribution infrastructure will be affected in the medium term as electricity generation is decarbonised and becomes more distributed, and the impact of new demands such as electric vehicles and smart appliances giving consumers more control over their electricity use. 2 September 2014
Renewable Energy Association, Professor Richard Green, Imperial College London and Professor Gordon Hughes, University of Edinburgh – Oral evidence (QQ 80-90)
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Renewable Energy Association, Professor Richard Green, Imperial College London and Professor Gordon Hughes, University of Edinburgh – Oral evidence (QQ 80-90)
Evidence Session No. 7 Heard in Public Questions 80 - 90
TUESDAY 18 NOVEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Baroness Sharp of Guildford Lord Willis of Knaresborough
__________________________
Examination of Witnesses
Dr Nina Skorupska, CEO, Renewable Energy Association, Professor Richard Green, Professor of Sustainable Energy Business, Imperial College London, and Professor Gordon Hughes, Professor of Economics, University of Edinburgh
Q80 The Chairman: Welcome to Professor Green and Professor Hughes. We understand that Dr Nina Skorupska is at the other end of the corridor giving evidence to a Select Committee of another place. They clearly are not running to time. Would you like to introduce yourselves first just for the record? We are being webcast so that will go on the record. If there is any opening statement either of you would like to make, please feel free to do so. Perhaps we could start with Professor Hughes.
Professor Hughes: My name is Gordon Hughes. I am a professor at the University of Edinburgh in Scotland and I have a large interest in energy economics. I have produced a piece of evidence, which I provided to the Committee a few days ago. I would like to tell a little story to illustrate the point that I was trying to make in that evidence and no doubt which will be repeated.
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In my spare time, I run community broadband networks using wireless and a number of those relays that we rely on are a long way from power supplies, so we use wind turbines and solar panels in order to provide them with electricity. The requirement in terms of capacity to ensure that we can have a reliable supply is that we need, roughly speaking, 10 times the amount of generating capacity as our regular supply together with a relatively large number of batteries as well. Even if you scale that up to the scale of a grid, there are two lessons that come out of that—first, that you can always supply electricity demand using renewable energy and it can be made reliable; secondly, there are two concerns that you have: one, you need storage and, two, you have to put up with some pretty high costs. The theme that is underpinning the evidence I provided is essentially that we can have as much renewables as we want in the UK. It is a matter of how much we are willing to pay for it. The question is really one of managing what is an acceptable cost in terms of the other tradeoffs that are involved. Thank you.
Professor Green: I am Professor Richard Green. I am the Alan and Sabine Howard professor of sustainable energy business at Imperial College Business School. I am an economist. I have been studying the industry for 25 years. Nowadays most of my research is funded by the Engineering and Physical Sciences Research Council, including a couple of projects looking at the economics of energy storage. I notice some of the questions on the roster seem slightly more engineer than economist, but fortunately I was at a meeting of one of my EPSRC projects yesterday and was able to ask some colleagues, with the clerk’s permission, to share that information.
The Chairman: Thank you very much. You do not want to make any further statement?
Professor Green: No, I think not.
The Chairman: I welcome Dr Nina Skorupska hotfoot from the other end of the corridor.
Dr Skorupska: My apologies.
The Chairman: I gather this is the first time you have given evidence to a Select Committee and you seem to be doing it rather intensively today. Welcome.
Dr Skorupska: Thank you.
The Chairman: As you have come in the nick of time, would you like to introduce yourself just to say where you are coming from? We are being webcast so that will go on the record. If there is any opening statement that you would like to make, by all means do so.
Dr Skorupska: Good morning, everybody. My name is Nina Skorupska. I am the chief executive of the Renewable Energy Association. I represent, on behalf of our members, close to 1,000 members. Two-thirds of those members are small to medium enterprises. We are very keen to see renewable energy deployed in order to achieve our low-carbon targets both in 2020 and 2030 and we want to see that as part of a secure and resilient electricity market in the future. We believe that renewable energy can play a significant part in that.
Q81 The Chairman: Thank you very much. Shall I start the questions? I would like to ask a fairly general question just to start, and perhaps I could ask Professor Green if he would like to respond first. What do you feel are the largest risks to the electricity system resilience in the short and medium term? I am so sorry. I am looking at the wrong one. How much of the United Kingdom’s electricity is currently generated by renewables and how much of the
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United Kingdom’s electricity do you expect to be generated by renewables under the best-case and worst-case scenarios by 2020 and 2030?
Professor Green: I looked up the figures from the Digest of UK Energy Statistics last night. Onshore wind was 17 terawatt hours. I did not get the percentages but that would be approximately 5% of the annual total. Offshore wind was 11.4 terawatt hours. Marine – wave and tide – was 6 gigawatt hours, which are fractions of a per cent. Photovoltaic was 2 terawatt hours last year and rising strongly, I suspect. Small-scale hydro, just under a terawatt hour; large scale, 4 terawatt hours; biomass, various kinds of waste including sewage and the like, was just under 10 terawatt hours; and plant biomass, a significant portion of which will be burning wood chips in large existing power stations, was 9 terawatt hours.
The Chairman: Would the others like to add to that before we move on?
Professor Hughes: You asked about 2020 and going on. The Government has a target, roughly speaking, for generating 30% from renewable sources and it looks likely that they are, roughly speaking, on target in order to do that. Originally, it was largely going to be achieved through wind. That is slightly less important and biomass, burning wood chips, will be slightly larger. The share can probably go up above that and probably is expected to go above that to 2030, but I do not think any of us have a very clear idea of exactly what it will be.
The Chairman: Could you speculate as to what might be the determining factors as to whether these figures are achieved or exceeded? Are there any particular influences that you can predict will have a bearing on this?
Professor Hughes: It is sort of a race between costs coming down—so if the costs of electricity from renewable sources declines as a consequence of technological improvement—against the willingness to provide funds for subsidies. At the moment the subsidies that are provided are capped under an arrangement called the levy control framework, which is set up to 2021. The question will be: is that sufficient in order to provide at current costs the level of incentives for generators to make investments in what are quite expensive sources of generation?
The Chairman: Clearly, innovation is unpredictable by its very nature, but we have seen, for example, PV costs come down quite rapidly to a point where some would say that such solar energy may be competitive with other sources from coal and the like. Do you predict that there are other such technological improvements that might alter the balance completely? Is it feasible, rather than can you predict it?
Professor Hughes: I think the story about what is called grid parity for solar is slightly exaggerated. What has happened is that the cost of the modules, the basic electronics in it, have come down a lot because of economies of scale and better experience, but that represents about a half of the total cost of building a PV installation, certainly on a large scale. The other costs have not come down at all.
The rate of decline in costs for most of these technologies has followed a pretty clear path, which is that they come down gradually, they level off, and then in some cases they increase. I do not think there is at the moment any obvious reason to believe that that pattern will be vastly different for any of the other technologies or, indeed, for that, but again there can be
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in 10 years’ time some fundamental technical innovation that is not predicted at the moment.
Dr Skorupska: May I come in?
The Chairman: Please.
Dr Skorupska: It is true that deployment costs will come down, whether it is technology or getting the supply chain more efficient and also with establishing the acceptance of that technology. You asked what would constrain the ability of renewable energies to be deployed. Well, it is not having clear policies, having vastly changing views on how those subsidies will be deployed, and also not having aligned overall strategy intents across the different departments of Government. For instance, we could be seeing more from waste-to-energy schemes, but at the moment we export a significant proportion of our waste to countries that do take advantage of having waste-to-energy schemes such as Sweden.
In some respects, there are opportunities that are still yet to be fully understood and examined, but in principle we will see wind technologies and their costs coming down with scale and deployment and the supply chain improving. We are also seeing it with the different behaviours of people in accepting and adapting to renewable energy as a part of the future. Who would have thought that many farms now would consider it would be of value to become a small power station on their locations, using their farm waste and producing from anaerobic digestion gas to produce electricity. At the moment, it is a very small scale but in Germany we have seen the adoption of that being tenfold the scale that we see in the UK. We do need an alignment of policies and regulations across the different departments.
Q82 Lord Rees of Ludlow: I would like to ask a bit more about the relative prospects for the different technologies. Looked at naively, it seems that solar will have more rapid technological improvements as compared to wind. On the other hand, we in this country have a lot of wind and not much sun so that tilts the balance the other way. In the light of that, could you say a little bit more about the relative balance you would expect by 2030 between those two forms of renewable energy?
Professor Hughes: The most clear reductions in the costs of solar in particular have come in environments which are very different from the UK. They have come in essentially desert, high-insulation areas of the south-west of the United States and elsewhere. Even there, at utility scale, the figures that are put together by the National Renewable Energy Laboratory in the United States on a fairly regular basis over quite a long period show that the decline in prices stabilised and pretty much stopped in the early part of the current decade. The wind one stabilised and stopped falling significantly about five years earlier than that.
There is one potential innovation in other parts of the world that might matter and that is solar thermal; in other words, not photovoltaics but essentially large-scale use of insulation in order to use conventional thermal generation. That has, apparently, the prospects of coming down a lot more in cost. It is still relatively new as a technology. I do not think it is going to make a great deal of difference in Britain but on a world scale it might.
Professor Green: Concentrated solar thermal has the great advantage that you can relatively easily put in a heat store and so the generation is not available only at the moment when the sun is shining, which is a key concern for us. I am not an expert in future cost predictions so I will not stick my neck out.
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Lord Rees of Ludlow: How far ahead do we have to look before we can talk about a DC grid all the way from southern Spain to the UK, thereby allowing us to benefit from sunnier parts of Europe?
Professor Green: The engineers are working on it. That was the meeting I was at yesterday. It would in many ways make more sense for us to have a share in some farms in Spain or even further south and the cables, but we are talking a decade or two at least, I would say.
Dr Skorupska: In terms of energy security and resilience, I believe that the deployment of solar within the UK is absolutely going to happen and would benefit the UK overall. The decentralised nature of these types of technology takes away the concerns of a lack of robustness of our overarching infrastructure; for instance, if a nuclear power plant does fall over. I have in my past 30 years of working in the energy industry run oil, coal and gas and been responsible for a nuclear power plant. We do see such large perturbations as we are seeing at the moment, the concerns for this winter, where three nuclear units are off because of boiler concerns; nothing to do with nuclear but just ordinary technology. Even in our northern latitude the sensors, the technologies around solar panels, as my colleagues have already said, is improving and will improve. It will cap but it is of value for the UK to have this decentralised energy incorporated.
Professor Hughes: Could I just comment? I simply do not buy that story at all and I have some directly relevant evidence. The Soviet Union in its old days developed long-distance DC grids over a very long way from Siberia to the Urals because they had lots of hydropower in Siberia and they had lots of manufacturing demand in Urals. It never worked properly and whenever we looked at the economics—and I did that on more than one occasion—it never made any kind of economic sense as well. It is very expensive to transport electricity rather than to transport the means by which you generate electricity. Unless you put a huge premium on essentially using the renewable sources rather than gas or whatever, it is always much better to transport gas.
Q83 Lord Rees of Ludlow: Could I ask one more question about other renewables, in particular waves and tides? These are clearly small players at the moment, but could you say a word about the Severn Barrage? This has been talked about a great deal. I know there are environmental problems, but there is also a cost issue that to me naively seems to be getting less acute given the Himalayan rise in the cost of nuclear. Do you think one should revisit the Severn Barrage?
Professor Hughes: The Severn Barrage is just a large hydro scheme, which is fed not by rivers but by the tide. Large hydro schemes can be made to work, undoubtedly. The trouble is that in order to make that particular one work you have to run it in two directions and mostly that is not normally the way that those kinds of things are done. I suspect what kills it is the environmental side of it rather than the underlying economics if you never had to worry about the environmental side.
Lord Hennessy of Nympsfield: I think I am right in saying that hydro was the first big natural source of energy that we invested in as a country after the war. Indeed, the Scottish system is called the hydro board, is it not? It seems to be a very small proportion. Is it because all the best sites in Scotland, Wales and the Lakes District have been used up or did we just lose sight of it?
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Professor Hughes: Hydro is a wonderful source of renewable energy. It is controllable. It is storage at the same time as a generation capacity. We are not Norway is the simple answer. That is to say we did use most of the available glens. There are other glens but nobody is going to find that easy to do because essentially it means taking things where we have much stronger views about protecting the landscape at the moment. If we were going to do that, the thing that we would want to do is probably not go for classic storage hydro but go for pump storage. Given the availability of wind and other things, pump storage is a much better match in terms of the limited head capacity that we have. We are never going to get a long way with that. Norway operates 95% on hydro power and could have 100% hydro power if it wanted. We are just not Norway.
Lord Rees of Ludlow: Pump storage is shutting it up and letting it down, is that right?
Dr Skorupska: Yes.
Professor Green: Yes.
Q84 Lord Willis of Knaresborough: I would like to bring you back to PV because I was quite depressed by your response and your little argument. I sort of buy into the idea that if, in fact, you are transporting photovoltaic or solar energy over large periods that it is difficult to make the economic case for that, but I thought that the big breakthrough was going to be in local and distributed systems. I understood that the original problem was the silicon substrates, which were very expensive in terms of panels, but there was to be a breakthrough in two ways in terms of plastic electronics so you could print the photovoltaic circuits very, very easily and very, very cheaply. Another technology was, in fact, that it was going to be embedded in glass. Given that virtually every new building that goes up in this city alone is simply covered with glass, why has that not become a technology that has been worth really investing in and developing?
Professor Hughes: Let me take two comments. First, suppose you completely stripped out the cost of the PV module, which in effect is that we make it so cheap that it is an irrelevant cost. Even with what is left, on a large scale the cost of installing the rest is more than the costs of a gas-fired powered plant or the like. Just without any concern about the photovoltaic element of it, that kind of cost is relatively high.
In terms of distributed systems, we may have very different views about that and, therefore, my colleagues may well say different things, but the basic point here is at the moment these are untested. They are highly experimental in terms of the way they work and almost certainly they rely on imposing costs that we at the moment do not recognise on managing the grid in an efficient way. The costs of a whole lot of grid changes that we need even to account for our current renewables are very large and if we then want to go to a distributed grid with intelligent controls in place, it may indeed work but do not, please, underestimate the costs of doing so because that has to be met from somewhere.
Professor Green: It is worth pointing out that quite a lot of the costs that Professor Hughes mentioned are that you get direct current from your PV panel and your house runs on alternating current, but a lot of the iPads and computers and devices I see around the place want direct current, so we have to rectify it back inside the device, thereby adding to their energy consumption. One of the presentations I was at yesterday was very much starting the technical exploration with European Union funding to start putting in supplementary networks inside houses to give those devices, which are a very high proportion of the
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average house’s load, the type of power they want. Once you had made the transition—it is not quick; it is not easy—you could take PV from your panel, direct current electricity, into your secondary house network, give your devices what you need and save quite a bit of cost.
Dr Skorupska: I am particularly excited by what we see happening in Europe and is coming to the UK linked with distributed renewable energy deployment, which is the rise of the view regarding the role that storage will play. Most people think of storage being large-scale grid, multi megawatt, helping to balance the system, but we are seeing the rise and rise of the opportunities coming from the deployment and the build of battery complexes to also service our potentially game-changing electric vehicle market.
I am no expert around battery technologies so please, if you know more than me, step in, but the general principle could be that in the future a home would have an electric vehicle, which in itself acts as a storage facility anyway. But if you also have photovoltaics on your house, which is the direction I am personally going in, if after three years your electric vehicle’s battery starts to degrade for use within your car, those batteries can have a secondary market as cassettes going into a storage cask in your home and, therefore, being able to smooth out your own personal usage across the full 24 hours without the need to then export your PV or the need to pull your electricity from off the system.
This could potentially be a game changer. This is the picture we were seeing in Holland where a consumer previously is becoming a prosumer. We are seeing the encouragement of things happening with heat as well for houses that are off grid, but the view that you could also use renewable electricity and the concerns around its variability and the intermittency it may cause to the system or the need for massive grid reinforcement costs. You could also see electricity being used for hydrolysis and the storage of hydrogen and also for hydrogen to be stored in the gas grid itself. The uses are many, different and exciting. How close they are to being commercial, that is what we need to work out with developers and also have the conversation with Government, but it is definitely being able to move away from the picture that you can only solely manage resilience of the UK energy by having large centralised units of what we have got used to since the 1960s and earlier.
Q85 Baroness Sharp of Guildford: I have first to declare that I have no interest in this area because this is the first time I have participated in sessions. I have been in Australia for the last five weeks. Having said that, let me put two questions to the panel. First of all, are we making enough use or projecting enough use of geothermal? Is that a potential source of generation and should we be thinking more about that? Secondly, as an alternative to generating electricity—and looking at the projections forward for the use of electricity we are projecting that domestic heating will switch over very substantially to electricity in the future—have we really made enough use of efficiency here? The concept of the zero carbon house is one that has been around for some time, but are we really pushing efficiency in reserving heat or preserving heat within the domestic sector enough? Is this not a potential big source of saving electricity and could we make more use of that?
Professor Green: My prejudice is that we are not making nearly enough use of energy efficiency. The builders will tell you, “If we have to make our house more efficient the price to the customers will go up”. Some fairly basic economics would tell you the price that people are willing to pay for their houses and are able to pay for their houses will stay the same. If the cost of building the house goes up a bit, and it probably would, the value of the land underneath it goes down, which is what the builders hate, but the value of the land
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without permission to build a shoddy house is very low. If a local council gives a builder permission to build a shoddy house, the builder makes a lot of money or the landowner makes a lot of money. If you give them permission to build a decent house, they will still make quite a bit of money but just not quite as much. They will tell you that this is a really bad idea for the consumers.
Baroness Sharp of Guildford: It is building regulations that are vital here?
Professor Green: Building regulations could do quite a lot, plus councils taking a slightly firmer line at least in those places where there is enough slack in land values that the cost would come out of the developers’ pockets, still leaving them with enough to make it worth while, and not areas where the land is too cheap for that to be the case.
The Chairman: Did any of you want to comment on the first point, which was geothermal?
Professor Hughes: Yes. I actually financed a geothermal plant in one of my past jobs and the answer is almost certainly in the UK, no, we are not making enough use of it. Geothermal can be an extremely cost-effective form of generation. The availability of the resources, however, is a significant issue. The second thing is we do have to straighten out somewhat the question of access to all kinds of underground resources on land because geothermal is not very different from fracking in a different way. It does not cause earthquakes because you do not put it in under pressure, but you are in effect doing the same things. You are taking account of an underground resource and pumping water in and out.
Essentially, we have in the UK collectively to sort out how we distribute the benefits that come from using those underground resources, but most of the figures that are done where there are good geothermal resources have geothermal as being competitive with, in effect, hydropower as a relatively cheap form of renewables that can operate in current market conditions without subsidies.
Baroness Sharp of Guildford: When you say we have restraint on resources, the big problem, in terms of financing, is that neither Government nor the private sector—
Professor Hughes: No, it is whether there is sufficient heat underground.
Baroness Sharp of Guildford: Yes, so it is natural resources.
Professor Hughes: Basically, what you are doing is you are pumping down cold water. You get out hot water, extract the heat from it and then do that cycle. There are other forms; heat pumps do the same thing, whether ground source or air source heat pumps, which are another way of doing it.
Baroness Sharp of Guildford: But you are going very much deeper.
Professor Hughes: You are going very much deeper. You are going down perhaps several thousand meters.
Baroness Sharp of Guildford: Yes.
Q86 Lord O’Neill of Clackmannan: One of the sources of geothermal that has been suggested has been Iceland. Professor Hughes, you raised questions about long-distance transmission efficiencies and costs. Given that we do not know how much geothermal there is in Britain—from what I deduced there is not going to be an awful lot, but we know there is an awful lot in Iceland and people tell us that is where we want to go—do I take it from what you have said already that, in fact, the transmission costs and the efficiencies of transmission
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would be against us developing a relationship with Iceland with a view to taking advantage of their geothermal resources?
Professor Hughes: Iceland has both geothermal and hydro resources, in fact, in substantial order. Almost certainly if we were thinking about going wider beyond the confines of the UK, the logical first area to go to for renewable sources would be Norway to try to tap into the hydro resources that they have there, which is what is done, in effect, by Germany and Denmark over much shorter distances. The lengths of a sub-sea, high-voltage DC cable from Iceland to the north of Scotland and then into the grid are forbidding but not impossible, but I think this is part of the thing that one has to have a lot clearer set of incentives about what we are willing to pay for in terms of the overall costs of any of these solutions. At the moment, we do not look at it in a system-wide way. We look at each individual technology on its own rather than taking a broader perspective about what is the cheapest way of meeting various requirements.
The other thing that we need to bear in mind is geothermal is classically run as a base load source of electricity. It is a substitute for nuclear. It is not a substitute for the intermittency of wind. It is meeting a different part of the electricity demand and a part where essentially the premium that you would pay is much lower than the premium you would pay when you are essentially substituting for intermittency at high periods of demand.
Lord O’Neill of Clackmannan: It all depends on what you call incentives and some of us would call subsidies, is that correct?
Professor Hughes: Indeed. I would put it in a more general way: what are we willing to pay for our overall electricity system; in other words, the costs that we incur for the grid, for delivering electricity to the grid, and then distributing that electricity to the consumers who want to use it in this very uneven way that they want to use it.
Q87 Lord Broers: I have a question for Dr Skorupska about what you have observed. There has, in fact, been very exciting progress with solar cells in the past year, as you will observe with perovskite cells that have gone from an efficiency of 4% to 20% this year and are much lower cost in manufacture than the silicon cells. There is also the possibility of stacking these cells with silicon cells to accomplish up to 40% efficiency. That might be more expensive cells. My question for you is: where is the UK placed in this? Are we competitive? I have been hearing about this in America and Australia, not here. Are we competitive?
Dr Skorupska: In terms of being—
Lord Broers: In perovskite cells. Evidently, at the international meeting 80% of the audience was in the perovskite sessions and about 10% or 20% in the old-fashioned cell session.
Dr Skorupska: It is an interesting question that you ask because we want to see deployment of solar to address delivering a renewable energy agenda and many of the members of the REA are already deploying current technologies of where we have seen significant costs going down. At the same time, many of our members are pushing the boundaries and working with their suppliers, either coming from Europe or China or listening and looking at what is happening in the States, to see what the next generation of solar panels will be. As you say, it is very, very exciting.
Are we world leaders here in the UK on that technology? I would argue not. But are we potentially going to be a significant player in wanting to deploy that technology and
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delivering a robust renewable energy at a very good value? I think we are. As technologies develop and costs come down and, as you also may be aware, solar attracts the most favourable support from the public, in having and seeing that new form of generation appear we will see a real game changer with solar being deployed in this country.
Lord Peston: I must confess that I am a bit lost because I am not sure what question we are on, but that is another matter. I hope I do not have to remind our two professors of economics of the appalling record of economists in forecasting in this area, going back to Stanley Gibbons, but many others have forecast the, “Woe is me, we are going to run out of sources of energy long before any of us are dead even”. What I ask myself and I am asking you two, one of our questions I thought was to press you to tell us about what the position would be in 2030. Unless I have gone deaf, I have not heard anything specific from you about 2030. Maybe the answer to that, if I were sitting where you were, is to refuse to answer that question on the grounds that economists are not very good at that sort of thing. Do you wish to tell us what the position will be on best and worst case scenarios in 2030?
Professor Green: Certainly, the strong advice from the Committee on Climate Change is that by 2030 the electricity system should be largely decarbonised.
Lord Peston: Decarbonised?
Professor Green: Yes, which implies some mixture of renewables, nuclear power, and fossil with carbon capture and storage; some energy storage may be an efficient way of dealing with intermittency; some amounts of probably relatively old fossil plant that does not have carbon capture and storage, so the emission per megawatt hour is horrible but they do not provide very many megawatt hours. One of the sad things is that our oil plant has been shut down over the last few years because of sulphur pollution constraints. If we had been able to keep those open they would be nice and flexible for backing up wind generation. That is the mixture. In terms of the particular mix that we would need to hit the target, particular percentages are difficult to get. There is very much an upper limit to nuclear, unless you wanted to ramp them up and down, which Professor Nuttall behind me will tell you is not a good idea later. Potentially there is not such a limit to carbon capture and storage plant, apart from the fact that it does cost more to build. If you build it and you do not run it very much it becomes relatively bad value, which is why I say keep some old stuff unabated because you will not use it much and if you do not use it much the pollution matters less but the capacity is useful when you have it.
Renewables depends a lot on policy decisions, how cost effective the support is. If you decide that you do not want an onshore turbine and build offshore turbines to get the same amount of energy, each turbine that you save onshore costs you £300,000 a year in additional subsidies for equivalent offshore capacity at the rates over the next couple of years, so there are quite a few policy choices. There are also probably policy choices that can minimise the subsidy we pay for any given project, regardless of what the actual engineering cost of building it is.
The Chairman: Did Professor Hughes want to come in briefly? We are running a little behind now.
Professor Hughes: Yes. I will accept the aspersions on economists. They are partly true but they are not quite as true as you imply. I think that there is in this issue a major disconnect between what is wanted—which is, in effect, what Richard is describing—and what will
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happen. Basically, the projections made by the likes of the Committee on Climate Change are your best case scenario from their perspective. What will happen I do not think will look much like that because we will not follow a consistent path of policy towards those kinds of objectives. It will also turn out, I suspect, to be far more expensive than can be accepted by the population at large, in which case we need and we will find the need to have a very different composition of outcomes.
I spent a lot of time working in the former Soviet Union in the period immediately after it broke up, and I had endless projections to cope with about how all kinds of large great projects ought to be developed, none of which ever happened and none of which were ever required. Therefore, what we have to do is plan for a flexibility in policy rather than make massive commitments that have very, very long shadows and very long commitments to expense well into the future. I know Dieter Helm said, “Look, in the end gas is the future for the next 10, 20 years”. I agree with him. In effect, we will have a lot more gas being used in 2030 than most of the visions of decarbonisation suggest.
Q88 Lord Broers: This all relates to this question about how much decarbonisation of electricity generation is going to cost. How do you respond to the suggestion that the costs of decarbonisation are simply too high? Professor Hughes, you sent us a very interesting evidence paper in which you are arguing that the hedging and balancing costs are such that if we go for the percentage of renewables that we plan to go for it is going to increase the wholesale cost of electricity by 70%. You stand by that estimate, do you?
Professor Hughes: Yes.
Professor Green: Professor Hughes, I assume that you were working off a graph like this one from Ofgem, which gives the hedge price of electricity. I do not know if that is the particular report.
Professor Hughes: Yes, that was—
Professor Green: Yes, that is the price after doing the hedging, £50 to £60 per megawatt hour. The total price paid on average by domestic customers over that period was £118 per megawatt hour, of which about half is the cost of the wires. That was the cost of the electricity after having hedged it. Any time you enter into a forward contract, Lord Peston will confirm that you do not know what the price is going to be and it may turn out to be bad value, it may turn out to save you money or you may wish you had not hedged. One estimate of what hedging costs would be related to the difference between what somebody would sell you a forward contract for and what somebody would buy a forward contract for from you a year ahead or so. Ofgem have done reports on that—Wholesale Power Market Liquidity documents, for example—suggesting that hedging spread is between 1% and 1.5% from a base load or a daytime-only contract over the last few years. That would be about 50p to 60p. I did some modelling based on stuff we did earlier. One measure of volatility is the gap between the price just averaged over the day—each is equal—and the average price you have to pay weighted by the amount of consumer demand. Once all the plant is adjusted, that would be about 12% higher with the current amount of wind. If you take it up to 30% that gap goes to 18%. There is certainly going to be an increase in variability, as Professor Hughes very much says. I would be very happy with his estimate and it may be that wholesale hedging might go up 40%, so that would add about 40p per megawatt hour.
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Dr Skorupska: If I could add the constraint payments, which is another way of looking at the cost of introducing variability, in 2012-13 we saw that the cost to consumers’ bills of managing and paying fossil plant, which received a significant proportion of all those costs, plus also costs to the wind generators to potentially back off from the market when it is a bit too windy, was under 1%. These numbers are very well known and tracked by DECC. In 2011 and 2012 the constraint payments were £325 million and the majority of that payment was made to coal and gas plants because of coal and gas plant behaviour. In fact, 90% of that, £289 million, went to coal and gas and only £34 million was paid to deal with wind. It is about understanding what those costs to the consumer will be in the future.
I would also like to pose a question back. What is the cost to the consumers of not doing these changes and introducing renewable energies? We are on a pledge to deliver 80% reduction of carbon by 2050 and now we have locked into the 40% reduction of carbon by 2030. My concern is not having clear, stable policies and a lack of transparency. One Member of the Committee had asked what is an incentive and what is a subsidy. I would also argue: what is a tax break? What is also another way of getting a level playing field of all the costs associated with delivering energy for the UK?
Lord Broers: But it is surely important that we understand the numbers and that we do try to come to some number for the increase in cost as a result of doing the socially responsible thing of increasing the number of renewable plants and our overall contribution for renewable. Could I ask you, Professor Green, what would be your bottom line number? Are you arguing that Professor Hughes’ calculation is not taking into account the delivery costs and, therefore, that dilutes the change of the wholesale cost of electricity? If so, what does he take his 70% down to—30%?
Professor Green: The work I did for the House of Lords Economic Affairs Committee six years ago showed an increase in cost for generation and transmission. Off the top of my head, based on the fuel prices of 2007-08, the cost of generation and transmission was going up by about 30% to 40%, which would be about 20% on the total price of electricity. I am not sure how that would relate to changes in the price of fuels since that point or changes in the costs of the renewables.
The work I have done on market prices implies that once the capacity is adjusted the market price probably does not change very much because it has to pay for all the other plants you get and that still needs the same amount of money. Then it is: what is the cost of the subsidy? At the moment, onshore wind costs £40 per megawatt hour more than current market prices, so if we got 10% of our energy from that, that would add £4 per megawatt hour to the average bill. You could perhaps say across various technologies £50 to £60 average extra, which, if that is a third, gives you £20 on the average bill. I am doing figures in my head as I am speaking. It would probably be rather better use of time to write a memorandum for the Committee.
The Chairman: Now that you mention time, we are running short of it.
Professor Green: Apologies.
The Chairman: I am going to ask Lord Patel if he will come in briefly.
Q89 Lord Patel: Briefly. You have all probably heard of Professor Dieter Helm. His evidence to us, which he put quite strongly, was that the current renewables cannot solve the problem of climate change. Further, he said that we should stop subsidising current
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renewables and invest more on R&D to improve future renewables; in the meantime, as regards the transition to gas, the world is awash with cheap gas currently, and this will reduce carbon emissions. He was quite robust in his evidence and I am hoping you will be equally robust in convincing otherwise or agree with him.
Professor Hughes: I unambiguously agree with him.
Lord Patel: I thought you might.
Professor Hughes: But the situation has to be seen in a slightly larger perspective. Renewables in the UK are a complete irrelevance in the world picture of climate change. Any technology that he is advocating has to work in China. The question you have to ask is: is this viable in Chinese circumstances? I spent a lot of my time working on Chinese energy problems. The answer to that is none of our policies are doing anything, apart from perhaps the promotion of carbon capture and storage, towards meeting that goal. Therefore, we would be much better off spending the money we are willing to spend to essentially ask the question: how do we decarbonise the Chinese electricity system? Because unless you do that, you can forget what we do here. Their annual growth in electricity capacity is greater than the UK’s or about equivalent to the UK’s total electricity capacity. There are more important things than worrying about wind in the UK.
The Chairman: Do any of the others want to respond to that?
Professor Green: Yes. China is critical and they are installing wind in a big way. Some technologies will get better by R&D. Some technologies have got to the stage where it is only going to be putting metal in the ground that leads to the experience which causes further cost reductions. The general argument that we should not do anything because we are so small compared to China is an instruction not to vote because in most constituencies other people will determine it. Certainly, doing everything with our technological resources, using a proportion of those resources to do China-friendly things, is almost certainly a good idea.
Dr Skorupska: Obviously, I will have a different view because I am a strong believer that we need to be deploying renewable energy now. We need to be working within Europe and particularly in the UK to show that we are leaders of wanting to live a low-carbon life. That is in the way that we deal with energy efficiency in our homes and in industry but also in the way that we determine to reduce our need on fossil fuels.
I believe gas should be seen as a transition fuel. My concern is that if we put all our eggs in one basket, which is the gas basket, we will never wean ourselves off gas because come 2030 we will have to have lost and started to put carbon capture and storage on gas. The question is: is carbon capture and storage even anywhere near commercial viability? I can say that wholeheartedly because I worked on it 10 years ago and we are no further forward. For me, that strategy of let us just do gas and put money into R&D is kicking the can up the road and the UK should not be seen to be doing that. There is a cost-effective way. We have to invest in our generation fleet now because of the decades of lack of investment in there. Why not just invest in it being a low-carbon future and renewable energy has to play its role in that? We can be world leaders on marine, that is absolutely the case, but yet we still do not have those supportive mechanisms to make sure we get tidal and marine away.
I do agree the UK Government should absolutely be working with China and using our engineering know-how along with some fantastic Chinese engineering know-how, which is
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deploying more renewable energy than they are doing in the other types of technology. It is not an either/or; it is an and. We have to do it and they have to do it.
The Chairman: Did Lord Patel want to come back?
Lord Patel: Yes, it was about the cost-effectiveness and the Government’s approach to renewable. Is it cost-effective?
Dr Skorupska: We have to make decisions and we want to see deployment now. We do know that if we deploy in volume we see costs coming down. The question back is: what is the cost of not doing it? Lord Stern made that case quite clearly that by taking action now, making our homes efficient, introducing renewable energy potentially in the homes and in industry, we absolutely decarbonise in a cost-effective way.
Professor Green: On cost effectiveness—
Lord Patel: On supporting the renewables.
Professor Green: Yes. The Government could make it more cost effective. At the moment it pays the same price for a unit of output for all wind farms commissioned in the same year. Some of them will be in very windy places and will have rather lower cost. If we followed the German scheme—about the one sensible bit of German energy policy—and paid less for wind farms in really windy places, they still make enough money. They can make more money than in moderate wind places, but we do not give them quite so much profit over and above what they need.
The Chairman: This will have to be the final contribution, from Lord Rees.
Q90 Lord Rees of Ludlow: Going back to the question of R&D, you were rather relaxed about us not being a leader in the latest solar PV technology. Do you not think it would be better if we were to have a real boost in R&D and try to be leaders there?
Dr Skorupska: It is about where we want to put our resources and I agree, R&D. I hate to labour the point. I was a managing director of a research and development team within Npower where we had limited resources and you had to pick which ones you believed that you would make the most difference in. You had to decide: what do we want to be leaders in? Which ones do we want to have a watching brief in? We have to be knowledgeable buyers but I do believe we need to pick some technologies to be leaders in. I cannot answer whether it is just solar but I definitely know it can be marine technologies.
Professor Green: One of my colleagues at Imperial who works on solar PV got her fellowship at the Royal Society this year. I will check with her whether we are active in that area.
Dr Skorupska: That would be good.
The Chairman: Thank you. I apologise to Lord O’Neill particularly who had one last question but we are a little behind the curve now. It is because we have had an interesting session. We have had a lot of questions to follow up and we could have extended this session, I am sure, for a very much longer time. Thank you to all three. Professor Green particularly, but perhaps others as well, has further written evidence that you have agreed to submit and we look forward to reading that. You will, of course, get a copy of the typescript to make minor alterations if you feel the record is inaccurate. Thank you once more to all three of you for helping us this morning.
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Renewable Energy Foundation, Dr Robert Gross, Imperial College London and Rupert Darwall – Oral evidence (QQ 167-175) Transcript to be found under Dr Robert Gross, Imperial College London
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Renewable Energy Foundation – Supplementary written evidence (REI0054) Author: John Constable Introduction I gave oral evidence to the Select Committee on the 13th of January 2015. These notes are more complete answers to the draft questions proposed to the panellists. They include my further views in relation to questions that I answered orally, and also views in relation to questions and matters on which I did not have the opportunity to comment. 1. Are the government’s energy policies likely to achieve its aims of a resilient, affordable and low carbon electricity system? There have been criticisms that policies such as Electricity Market Reform have brought back large-scale government intervention. Do you think these policies strike the right balance between a market-led approach and Government intervention? The Secretary of State, Mr Davey, himself confirms that it is a dirigiste instrument. He wrote to the Guardian a few days back (09.01.15) responding to an editorial calling for more intervention saying:
“our reforms of electricity markets, both for clean energy and for securing supply, are significant state interventions in the free market.”171
Of course, Mr Davey is correct. Indeed, the EMR documentation actually uses the term “administrative pricing” in relation to FiTs CfDs, so there can be no real doubt that there really is substantial and growing coercion of the electricity supply industry. Since in my view the market was already excessively distorted by instruments such as the Renewables Obligation, and the Feed-in Tariff, and indeed the Climate Change Levy, the further extension under EMR is very unwelcome, and in effect transforms the sector into a government policy delivery instrument, largely a climate policy delivery instrument. Consequently, very many charges imposed on the consumer are now no longer visible to a competitive market, consequently the likelihood that the consumer will be needlessly disadvantaged is high. In view of this EMR and the associated interventions are clearly unsatisfactory and unlikely to be stable. If you want a prediction about the likely trend of future reform, I have a hunch that it may come through a recognition that competition can be best returned to the sector through competitive tenders for both capacity and energy. The Institution of Engineering and Technology has called for further intervention through a new ‘systems architect’. Is such an architect required in your view? Clearly something has to change, particularly with the role of National Grid, which is conflicted. However, reforms consistent with the spirit of the IET’s recommendation, or
171 http://www.theguardian.com/business/2015/jan/09/we-have-intervened-in-the-energy-market
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Professor Helm’s recommendation of an Energy or Electricity Commission, do not necessarily have to render the market less liberal; on the contrary. For example, a not-for-profit Standing Commission might take over many of the roles currently undertaken by National Grid, for example the system design, the asset management and the System Operation, all features related to security of supply of course, while the Transmission Ownership could remain in private hands, indeed ownership could be removed from ‘price regulation’ and thus opened up to competition. This would simultaneously address concerns at the lack of a responsible party to guarantee security of supply, but also resolve the worrying conflict of interest whereby National Grid not only designs the system but also earns a regulated income from that asset base, the grid lines and other equipment. More grid to connect wind farms is extremely positive news for National Grid and its shareholders. I realise that is an elliptical answer, so, as an appendix to this evidence I am submitting a Discussion Paper prepared for REF by Mr Gibson, formerly Power Networks Director for National Grid. 2. Are sufficient steps being taken by the government, regulator and National Grid to ensure the resilience of the electricity system? Are National Grid’s New Balancing Services likely to be sufficient to balance supply and demand over the next two winters? National Grid are superb engineers and they are clearly under some considerable pressure to ensure that there is no problem in the short term, regardless of the cost, so I am less concerned about the risk of system fragility in the short term, and more concerned about the cumulative oncost of measures taken in the short term interest and of the precedent set. Will the Capacity Market be effective at balancing supply and demand in the medium term? Is there a risk that too much capacity will be supported, and the costs to consumers will be too high? The answer to the first question is probably yes, but there is considerable doubt over whether it will produce an optimal outcome. There clearly is a risk that costs to consumers will be high. This is, after all, distressed policy correction. That’s always expensive. Is it going to be still more expensive than it needs to be? From the consumer perspective, almost certainly so. The cost of maintaining security is a result of a trade-off between the cost of the necessary measures and the value of lost load. You have to ask whether the right security standard been chosen. It is quite conceivable that some consumers might prefer lower costs and a higher level of the risk. But of course the current measures are largely under political direction, and of all people politicians are probably the most sensitive to blackouts, and the most willing to see high indeed any costs in order to prevent them. Of course, the cheapest method of limiting cost and improving system security is to address flaws in the policies, particularly the renewables policies, that are imposing the costs
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through their own inherent character and the fact that so large a subsidised sector has destroyed investment signals in the rest of the market. Does the Capacity Market provide sufficient promotion for measures such as Demand Side Response and interconnectors? If not, how could this be addressed? Covered in oral evidence. 3. How much is decarbonisation of electricity generation likely to cost? How do you respond to the argument that these costs are likely to be too high? How do the costs of onshore and offshore wind compare to those of other low carbon generation technologies, including CCS and nuclear power? As is well known the levelised cost of onshore wind is roughly double that of conventional generation, without CCS, at about £100/MWh, and Offshore wind rather more at about £150/MWh. One of the better studies on this subject in recent years suggested costs of about £100/MWh for nuclear, and about £145 for coal, and about £110/MWh for gas with CCS. Those are approximate figures; the precise numbers can be checked. But it is now very well known that the levelised cost methodology does not permit proper comparison of despatchable and non-despatchable plant. Some Total System Cost estimates taking into account all the extra cost imposed by uncontrollable intermittent generation, have suggested that onshore wind is around three times the cost of CCGT at current gas prices, and offshore wind about four times the cost. That’s a very expensive CO2 saving route, and extremely unlikely to be economically compelling or to stimulate spontaneous adoption. How do you expect these costs to change in future? Will the gap between the costs of low carbon generation and those of conventional fossil generation close? With falling international oil and perhaps gas prices there is every reason to suppose that renewables might become cheaper, since fossil fuels are a significant part of their construction and installation costs. However, the cost of fossil fuel electricity generation will fall as fast if not faster, so the relative cost gap will remain the same or widen. The entire renewables policy, in this country and the EU, was a gamble on the future price of gas increasing significantly, and that gamble has failed. Even if that effect is only temporary, five or ten years say, the current policies look ludicrously premature. Some say that wind imposes particularly high additional costs on the electricity system to pay for grid integration and backup generation. How significant are these costs, and how will they change if the contribution of renewables continues to grow? There can be no reasonable doubt that the system management costs are high. I refer the Inquiry to the work of Colin Gibson, a former Power Networks Director for National Grid, for IESIS. Gibson’s central estimates for 2020 of wind’s additional cost of system management,
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over and above that conventional generation, is about £75/MWh for onshore wind, and £64/MWh, the difference being accounted for by the higher load factor of offshore wind. Thus: the total cost to consumers of onshore wind would be about £170/MWh, and offshore wind about £209/MWh. In 2011 we at REF calculated that for the 2020 plant mix then predicted, the subsidies would be about £8bn a year, and the system costs another £5bn a year, almost as much again as the subsidy. Gibson’s estimates include a) The cost of short term reserve, to address errors in the wind forecast; b) additional grid and grid reinforcement; and c) the cost of guaranteeing security of supply at current levels by retaining sufficient conventional plant equal to peak load, plus a margin, but running that portfolio at necessarily lower load factors. 4. What are the options for overcoming the challenges of intermittency? What would the most cost effective approach for achieving this be? How much of a contribution can – or should - different technologies such as flexible generation, interconnection, electricity storage and demand side response make? The most cost effective approach is to avoid incurring the problem in the first place. None of the means of addressing the problems caused by uncontrollable variability are affordable at the large scale that would be required in 2020, assuming that the EU RE Directive levels of renewables are met by the current expected mix of wind, solar and other technologies. I can illustrate this point in relation to constraint payments. As the committee will know wind power makes negative bids in the Balancing Mechanism, which are unusual, indicating that it requires to be paid to stop generating, and that has resulted in direct costs for wind farm compensation alone of about £50m in payments within the Balancing Mechanism alone. At just over £70/MWh these bids are in fact well in excess of the lost income of about £45/MWh. It is true that the prices have fallen; when REF first publicised this abuse of market power the top negative bid was £999/MWh, and the mean was £178/MWh. On top of the cost of those negative bids is the cost of paying conventional generation to come on to make up for the now missing wind. It is not quite straightforward to assign constrained on payments south of the constraints to these wind export constraints, but it will be substantial. Now, you might think that the obvious solution to this is to reinforce the grid between Scotland and the centres of load in England. But that too is very expensive for the consumer. The cost of extra grid must be recovered from consumer bills at the rate of about 10% of the capital cost per annum for the life of the asset. So one single billion pound bootstrap subsea interconnector would be adding about £100 million a year to consumer bills, for thirty years or so.
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There really are no cheap solutions to these problems. Indeed constraining wind power off the system, though not at current prices, might be a comparatively cheap option. Further details on constraints: 1. Projected BSUOS cost for the year ending Mar 15 (where real costs exist up to Nov 14) is approx. £1bn of which constraints is roughly a quarter £250 million. Last year the out-turn was also approx. £1 bn of which constraints were £340 m – so a third. (They may be being optimistic for this year – we shall see). 2. The £250 million includes export and import constraints – but export constraints represent over 90% of the total and the two Scottish constraint boundaries 82% of the total. So it is reasonable to assume that Scottish wind is the major problem. 3. What proportion of the total cost is attributable to wind is impossible for outsiders such as REF to calculate. Direct costs payable to wind generators was approx. £50 million (BM and forward trades) for year ending Mar 2014 – so one could jump to the conclusion that wind is 20% of the whole but that ignores the replacement costs. If we had to guess, we would say that the extra indirect costs are probably the same again i.e the replacement and reserve replacement is about £60-£70/MWh – so perhaps total cost of the Scottish overbuild of wind is £100 million so, a conservative estimate, 40% of the current constraint costs are attributable to wind power. To what extent are the Government’s current policies likely to deliver the most cost-effective solutions for managing intermittency? The current approach, well represented by the Connect and Manage scheme is simply to write a blank cheque on the consumer. This is very unlikely to deliver a cost effective result. The simplest and cleanest solution in the short term would be stop building intermittent renewables, of which we already have more than is economically or technically prudent, and build CCGTs. Does increased reliance on renewables inevitably reduce the resilience of the electricity system? Yes, if we are talking about uncontrollable renewables, since these renewables increase the system costs of providing a given level of security, and thus it is inevitable that consumers will be compelled by economic necessity to settle for a new equilibrium with lower levels of security. The current levels of intermittent renewables are already dangerously high; we should stop making the problem worse and without delay build gas turbines for support purposes. 5. In an earlier evidence session, Professor Dieter Helm argued that current renewables cannot solve the problem of climate change. In his view, we should stop subsidising current renewables, invest in R&D for improved future renewables and in the meantime rely on gas to reduce carbon emissions. To what extent do you agree with this argument?
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I agree in almost every regard. The current renewables policies will be so expensive, as much as £13 billion a year in additional consumer costs in 2020 as I have already noted, that consumer rebellion is all but inevitable. Professor Helm’s suggestion is much less likely to stimulate public resistance, and stands a much better chance of delivering clean technologies that are spontaneously attractive without subsidies. Furthermore, it is more likely to deliver more significant and cheaper carbon emission reductions. His views have been neglected for far too long. That said, the track record of state sponsored R&D is poor, and it seems rather likely that the tradition of picking losers would continue. A technology neutral carbon tax to encourage private R&D would be obviously be preferable, or perhaps tax breaks for private R&D. In your view, is the government’s current approach the most cost effective way to support the deployment of renewables? If not, what would a better approach be? It is hard to imagine anything more wasteful than the current mixture of the ETS, the RO, the FiT, the FiTs CfDs. I appreciate the legal difficulties, but the sooner these instruments are terminated, retrospectively if possible, the better. If we must have an instrument, then there must be only one, and it must be a technology neutral carbon tax. To what extent can an increased role for gas provide an alternative way to meet our emissions targets? What are the resilience implications of this? It’s the wrong question. The 2050 emissions targets cannot be met by the renewables policies any more than by a switch to gas. Gas will deliver what emissions reductions are affordable, that may not perhaps be at the absurd scale demanded by our (2050 aspirational) targets but quite sufficient to constitute a reasonable insurance policy against climate change, and at an entirely reasonable price. Furthermore, national wealth and societal sophistication will be maintained, putting us in a better position to invent and innovate our way towards a fundamentally economic low carbon energy supply, as well as adapting to climate change and helping others to adapt. Are there any game changing technologies which would help to improve resilience, and on what timeframe might these be market ready? No comment. 21 January 2015
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Appendix 1: Mr Colin Gibson on an alternative to nationalisation for the Electricity Supply Industry The following discussion paper has been drafted for Renewable Energy Foundation by one of the foundation’s advisors, Mr Colin Gibson, a former Power Networks Director of National Grid.
AN ALTERNATIVE TO NATIONALIZATION OR PRIVATIZATION OF THE ELECTRICITY SUPPLY INDUSTRY IN GREAT BRITAIN
1. Introduction 1.1 A recent poll (The Times, 02.12.14172) has shown that a majority of people in GB would prefer a return to a nationalized Electricity Supply Industry. This paper offers, for the Generation and Transmission sectors, an alternative to either staying as a fully privatized industry or a return to a nationalized one. 1.2 There are a number of weaknesses in the present arrangements.
There is no body responsible for ensuring Security of Supply
NETA and BETTA did not recognise ‘power capacity’ as a separate commodity, and although the recent capacity auction for 2018 is a step forward, it does not provide an overall optimisation.
There could be a conflict of interest in the different roles of National Grid 1.3 The arrangement suggested in the current study endeavours to retain competition in as many as possible of the functions involved and to reduce the number of functions requiring ‘price regulation’. It introduces a central planning body to make effective long-term decisions in areas where the current energy market has failed to deliver a secure and economic supply. 1.4 The current arrangement of a single market in energy will not deliver an optimal solution relying as it does on that market to deliver the optimum plant mix at the optimum time. This is because there are two commodities involved – energy [MWh], (the basis on which to the customer is billed), and power capacity [MW] to meet instantaneous demand, particularly at times of peak demand. Since these two commodities are to be delivered from the same items of capital plant - generation units – there is a need to find a plant mix that will satisfy both requirements at minimal cost. This paper offers a method of achieving an overall optimum solution. 2. Long-term Planning
172 http://www.thetimes.co.uk/tto/news/politics/article4284493.ece. Poll details appear in Appendix 1.
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2.1 In order to provide effective and optimal planning and delivery of the total GB system, it is proposed that a Standing Commission reporting to Parliament be set up with the following duties.
It would propose a Standard of Security of Supply to be endorsed by Parliament. The Standard would be equivalent to that for other developed industrial countries and that used in GB prior to privatisation.
It would commission study work on a total system cost basis to find the optimum ongoing plant mix to minimise cost and meet the Standard of Security of Supply. The costs would include all generation, transmission, losses, and system costs such as back-up for intermittent generation. The study work should be on a probabilistic basis to accommodate the range of input values over the long period of the studies.
It would address the issue of long-term plant mix in order to have acceptable security for prime sources of energy.
It would address other limitations such as CO2 emissions. 2.2 It would put out tenders for generation plant to meet the optimal ongoing plant mix. The tenders would be for a capital cost part that would be for power capacity to be delivered at times of system peak demands (triads?); and a revenue cost part for the delivery of energy including hot, cold and warm starts, run up heat rates, amongst other matters. The tenders would be assessed on a total system cost model using discounted costs. 3. Operating the System 3.1 The Commission would place contracts for the most attractive tenders. The System Operator (SO) would schedule and dispatch generating plant on the basis of the contracts using methodology similar to that formerly used in the POOL to achieve minimum cost. ‘Grandfathering’ would be required for existing generators. The generators would be compensated on the basis of the revenue part of their tender to the Commission which would be embedded in a long-term contract with suitable escalation clauses for fuel, salaries and other works costs. 3.2 The methodology used would take account of the costs of response and reserve plant, losses, and all system costs to control voltage and frequency. These would be delivered under ancillary services contracts between the SO and the individual generators. 3.3 The delivery of power capacity at the times of peak demand would be contractual and payments made on the basis of the capital cost part of the tender. If the contracted generator did not have sufficient capacity available to meet its contract it would have an obligation to purchase and supply to meet its contract. (This is the same as the CfDs in the POOL). Failing this, there would be compensation to be paid by the generator on the basis of Value of Lost Load specified in the contract. 4. Organizational Changes
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4.1 Other than setting up the Commission, the main organizational change suggested would be within National Grid. National Grid carries out several functions for the GB ESI.
The System Design function delivers plans for the extension, modification and replacement of plant on the basis of requests to connect new generation, load increases, and replacement of time expired plant in line with the Standard of Security of the Transmission System. But does NG really have Design Authority given that the Regulator decides whether a ‘need’ case exists? There is a potential conflict of interest here also since NG as the plant owner receives a return on its Regulatory Asset Base and thus has an interest in expanding it.
NG has a responsibility for Asset Management of the transmission plant with regard to its specification, condition, maintenance routines etc.
NG is also System Operator for GB.
NG maintains the plant to the standard required by Asset Management, and project manages new construction work and is also the Transmission Plant Owner.
4.2 Some of these functions may sit more effectively with the Commission which would be structured as a ‘not for profit’ organization. In particular, the functions of System Design, Asset Management, and System Operation are together accountable for the security of the transmission system and should be kept together under one corporate body. They have a very small requirement for capital assets (mainly for SO) and could easily sit as a wholly owned subsidiary of the Commission itself. This removes the possibility of a conflict of interest between System Design and Transmission Ownership. 4.3 Transmission Ownership (TO) could then be open to competition for any new project since this is essentially a banking function – infrastructure companies tender to finance a project for new plant Existing transmission plant could be ‘grandfathered’ with National Grid and receive the Regulator’s Rate of Return. The TO could be made accountable for the maintenance of the plant to the standard required by the Asset Manager. The Transmission Ownership, by far the largest of the financial items within the Transmission function, is thus removed from ‘price regulation’ and opened to competition. Colin Gibson 13 January 2015
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RenewableUK – Written evidence (REI0039) Summary 1. RenewableUK welcomes the opportunity to respond on behalf of the wind, wave, and
tidal energy sectors to this House of Lords Inquiry. Our key thoughts relating to this Inquiry are as follows:
There is a need for stability in support for low-carbon generation, in order to bring forward technologies that have lead-in times of several years.
Renewable generation such as wind, with its flexibility of response, has been shown to be able to support grid stability.
Variable renewable generation does not require new “back-up” plant, but rather operates beside flexible thermal plant at moderate capacity.
We need timely investment in grid infrastructure in order to facilitate both the connection of renewables and the facility for generators to contribute to system stability.
The decarbonisation agenda needs to be supported by the evolutionary deployment of complementary technologies, notably Interconnection, storage, and demand side response.
Introduction 2. RenewableUK is the trade and professional body for the UK wind and marine renewables
industries. With some 600 corporate members, RenewableUK is the leading renewable energy trade association in the UK, representing the large majority of the UK's wind, wave, and tidal energy companies. The association’s response aims to represent these industries, aided by the expertise and knowledge of our members.
3. RenewableUK has two key interests in the sphere of the resilience of electricity
infrastructure:
Securing appropriate investment in the electricity networks: Too little investment, and new generators cannot easily connect and export their power. Too much investment, and the network charges increase for all generators connected to the system. The renewables sector also has an industry interest in avoiding unnecessary increases in consumer bills, as this can weaken support for renewable energy from both the Government and the public.
Ensuring more variable generation can be accommodated by the electricity system: “Passive” renewable generation and new tools would mean that the System Operator and the network companies need to rely on convention fossil fuel generators to provide support services. More pro-active renewable generation means that wind and other generators are able to provide support services directly, and can replace the thermal plant currently relied upon.
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4. Our response below addresses some of the specific questions raised by the Inquiry, focusing on the relevance and contribution of the renewable energy sector.
To 2020: How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base? 5. National Grid provide a number of documents examining resilience with respect to peak
demand and other system issues that may arise from time to time, both in the near and longer term. This includes: The Winter (and Summer) Outlook; Electricity Ten Year Statement; Future Energy Scenarios; The System Operability Framework (the first version is currently out for draft). Similarly, Ofgem’s Electricity Capacity Assessment provides analysis on some of these topics.
6. We consider this suite of documents overall to be robust and extensive. All of these documents highlight new challenges that the system will face in the future as the system is decarbonised, though none point to a world where these challenges are insurmountable such that system security is compromised.
7. With regards to ‘shocks’, an emerging issue to note is with the connection of ever larger
CCGT and new nuclear units (some are expected to be 1,800 MW), and the system’s ability to deal the sudden loss of these units. Work is ongoing to address this.
To 2020: What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to “keep the lights on”? 8. We will not comment on wider market developments, but rather observe the following
in relation to renewable energy:
National Grid and the wind industry are working together to develop the provision of ancillary services, such as frequency response, from wind generators to the System Operator (SO), such that there is no need for the SO to rely on thermal plant for these services. The recently published System Operability Framework also sets out likely system needs with respect to commercial and technical services in the near, medium and longer term future.
National Grid is also developing a mechanism for provision of a “rapid frequency response” service, whereby highly flexible wind generation can act rapidly to respond to any system disturbances, in view of reductions in the inertia of the system as a whole.
Windfarms are already providing voltage stability services and can be expected to play an increasingly important role with respect to system stability in the future.
To 2020: How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? 9. From the perspective of renewable energy, what is key is to have adequate investment in
grid infrastructure, such that:
renewable generators can get connected
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renewable generators can be relied upon to provide support services as appropriate to National Grid
10. The eight-year price controls for the transmission and distribution companies have
recently been agreed for grid investment into the 2020s. However, RenewableUK believes the investment is not sufficiently pro-active. As a result, investment in grid infrastructure is not a driver of new generation connections; rather it is an impediment. In essence, “the house is built first, the road properly built out later.” We are aware of areas of the country where the grid is congested, with grid connection offers out to 2023 or longer, i.e: new generation cannot connect until well into the next decade.
To 2020: What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable, and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? 11. In order to be confident of adequate investment in new generation into the 2020s, there
is a need for stability in support for low-carbon generation, particularly for large offshore projects that have lead-in times of several years. At the moment the new arrangements under Electricity Market Reform (EMR) for renewables support, limited by the Levy Control Framework and annual budget bands, are sufficient only to support one medium-sized offshore wind project per year. This is not the way to develop a confident British industry supply and delivery chain in the long-term, nor a sound basis on which to make long term, cost effective decisions on the necessary supporting infrastructure.
To 2020: Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure? 12. The key to sustainable, clean energy is cost reduction. Over the next six years,
RenewableUK expects the cost of onshore wind to continue on a downward trend, with the major limitation to further deployment being that of land use considerations. With offshore wind, as larger plant are built further out to sea and technology innovation increases, costs will follow a clear downward trajectory..
13. The offshore industry is committed to a cost reduction of one third in the Levelised Cost
of Energy (LCOE). However, this reduction is dependent on confident volume deployment. Without the appropriate support under the Levy Control Framework, offshore wind will be deployed in a piecemeal way without the economies of scale and supply chain efficiencies that can deliver the cost reduction.
To 2030: What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience? 14. It has already been noted that wind generation can support system stability
(“resilience”). There are a number of additional tools that are complementary to the deployment of variable, asynchronous generation such as wind. These tools are:
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flexible thermal plant
interconnection to other energy markets
storage
demand side response 15. Each of these tools needs further strategic development. 16. Flexible thermal plant continue to be supported through EMR arrangements. 17. On Interconnection, we are pleased at the recent progress made by Ofgem to issue a call
for Interconnection proposals to 2020. We look forward to the outcome. Our concern is that the arrangements for economically beneficial trading over Interconnectors may not match the shorter-term / real-time operational needs of the System Operator. We believe a further study is needed to ensure that Interconnection arrangements act in support of system stability.
18. On storage, we welcome the work currently being undertaken under Ofgem’s Smart
Grids Forum, to address the regulatory and commercial barriers to the deployment of storage solutions. However, in general storage solutions are still somewhat expensive for simple energy storage, and there is a need to break down the commercial and regulatory barriers to alternative revenue streams. We would support, following on from a strategic review of the variety of roles storage can play, either independently or as a complementary technology to renewables (for example), a Government target and associated support scheme for storage, to facilitate its deployment and eventual reduction in costs.
19. On demand side response, we welcome the arrangements already in place, and further
arrangements under development, for demand side to contribute to balancing reserve. The advent of smart metering and smart grids will increase the potential for demand side response to be used. We support the timely roll-out of smart solutions.
To 2030: What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? 20. We refer again to National Grid’s System Operability Framework, which sets out
scenarios for a range of system issues out to 2035. What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? 21. A clear, firm, long-term commitment to deployment of renewables across the policy
spectrum – energy, planning, fiscal – will ensure a healthy and robust market with long term visibility to the System Operator and regulator as to the future energy mix. Against such a background, planning for future system security – both in terms of network upgrades and system operation – can be made with greater certainty and less
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redundancy, thereby minimising cost to consumers. It is therefore imperative that investors are given long term signals around future support for renewables (for example though greater visibility of the Levy Control Framework budget into the 2020s) on which to base investment decisions. Regulatory decisions must also be aligned with Government aims on decarbonisation to achieve these goals.
To 2030: Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? 22. As set out above, the cost of energy from renewable technologies such as onshore wind
and offshore wind, but also wave, tidal, and other technologies, is set to decrease significantly. It is worth noting that consumer support in the electricity sector is not restricted only to emerging or immature technologies. Nuclear power is also to be supported under the Contracts for Difference regime. It is the job of Government to evaluate the trade-offs in terms of costs and generation profile of various technologies in the pursuit of energy security and system resilience. However, we would note that the fixed ‘strike price’ that the new Hinkley C development will receive is higher than that of onshore wind and that the contract length, at 35 years, represents a significantly longer consumer commitment than the 15 year contract available to renewable generators.
23. The volume of deployment to deliver such cost efficiencies is however reliant on longer-
term Government support. For instance, if offshore wind continues to be deployed further out to sea, the learning from these projects may yield solutions such as floating turbines, i.e.: turbines fixed to a floating platform that is anchored, rather than turbines that are fixed to a base in the seabed. Moreover, we are already seeing the development of larger, more efficient turbines such as the 6MW Siemens offshore turbines recently installed at Gunfleet Sands off the Kent coast. MHI Vestas is also developing an 8MW offshore wind turbine which is currently being tested in Denmark. These and other turbines in development represent a significant increase on the current 3.2MW Siemens turbine which has been the dominant model in the UK offshore market. These short and medium term innovations have the potential to deliver significant cost reductions for offshore wind.
Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system? 24. The UK is currently the leading country in the World in the deployment of offshore
renewable generation. Over half of Europe’s offshore wind resource lies in British territorial waters, and the industry is a natural extension of our maritime history, including both shipbuilding and oil and gas drilling.
25. We do not claim to have a single answer to the UK’s energy needs, however we believe
that with head start the UK’s clear competitive advantage in offshore wind, the
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technology’s generation, industrial and export potential offshore wind should be given a realistic opportunity to be realised. The alternatives on the table to increased deployment of offshore wind generation are Carbon Capture and Storage (CCS), about which significant cost and technology uncertainties exist as commercial-scale demonstration plants are developed; or a significant increase of the UK’s existing nuclear ambitions, with a consequent long-term consumer support commitment, as noted previously.
Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects? 26. We commend Ofgem’s Low-Carbon Networks Fund (LCNF), now Low-Carbon Networks
Innovation (LCNI), as a much valued resource for innovation projects and the sharing of learning. However, we believe more is needed: Rather than a call for innovation projects on any theme, we would like to see a strategy for innovation, with prioritised themes that require an answer by a particular time.
27. This would make such innovation support more strategic and more effective in informing
solutions to problems as these appear on the horizon. Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? 28. We have set out above our belief that there is a need for more effectiveness in grid
investment decisions, such that grid infrastructure is available for when the market delivers, rather than acting as an impediment to market solutions.
19 September 2014
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Resilient Electricity Networks for Great Britain (RESNET) project – Written evidence (REI0025) Prepared by:
Mathaios Panteli and Pierluigi Mancarella (The University of Manchester) Contributors: Kevin Anderson, Dan Calverley, Ian Cotton, Richard Dawson, Gaihua Fu, Dana Abi Ghanem, Steven Glynn, Clair Gough, Xiaolong Hu, Chris Kilsby, Jaise Kuriakose, Sarah Mander, Lucy Manning, John Moriarty, Cassie Pickering, Jiashen Teh, Sean Wilkinson, Ruth Wood
1. Introduction Boosting the resilience of UK’s electricity infrastructure in the short term (2020) and in
the medium term (2030) future is critical for withstanding peaks and pattern changes in demand and sudden shocks in supply. The future UK energy network should go greener to meet the requirements of its climate change targets by applying drastic measures such as decarbonizing its electricity generation, but should also be resilient to unforeseeable external shocks, such as extreme weather events. This leads to the so-called “low-carbon resilient” networks173, which imposes several challenges in the design and operation of the future UK energy system.
To address these multiple challenges, the Resilient Electricity Networks for Great Britain (RESNET) project is: - Developing and demonstrating a comprehensive approach to analyse, at a national scale,
climate-related challenges in the resilience of the UK’s electricity system; and - Developing tools for quantifying the value of adaptations that would enhance its
resilience. The RESNET project comprises five discrete work packages, ranging from electricity
demand and supply scenarios to a systematic resilience analysis of the UK power network, evaluation of adaptation measures, and social responses to these measures. The project is funded by the Engineering and Physical Sciences Research Council (EPSRC) and it is a consortium of Universities and research centres (University of Manchester, Tyndall Centre and Newcastle University), supported by stakeholder partners (National Grid, Environment Agency and Ove Arup).
This letter is a collective response by the RESNET project to the “Call for Evidence: Resilience of Electricity Infrastructure”, which summarizes the key findings of the project so far.
2. What is “Resilience of Electricity Infrastructure”? The electricity infrastructure, as a critical infrastructure, must be reliable during normal
conditions and in response to foreseeable threats. In this respect, its design and operation have traditionally been driven by the key reliability aspects of security and adequacy. However, it is becoming increasingly apparent how the critical electricity infrastructure must
173Modassar Chaudry, Paul Ekins, Kannan Ramachandran, Anser Shakoor, Jim Skea, Goran Strbac, et. al., “Building a Resilient UK Energy System”, UKERC/WP/ES/2009/023, UK Energy Research Center (UKERC), March 2009.
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also be resilient to high-impact low-probability events, such as extremes of weather. In the light of climate change, this is increasingly important as the frequency, intensity and duration of extreme weather events is expected to increase in the future174.
In this context, resilience is defined as the ability of a power system to withstand extraordinary and high-impact low-probability events (sudden shocks) such as extreme weather events, rapidly recover from such disruptive events and absorb lessons for adapting its operation and structure to prevent or mitigate the impact of similar events in the future. According to Cabinet Office, UK175, and the National Infrastructure Advisory Council (NIAC), USA176, the key features of resilience are robustness/resistance, resourcefulness/redundancy, rapid recovery and adaptation. Adaptation refers to the measures taken to reduce the vulnerability and build resilience and it can be defined as the process of adjustment to actual or expected climate and its effects, in order to moderate harm or exploit beneficial opportunities177.
However, building highly resilient networks to extreme weather events, and in general to the challenges introduced by climate change, is a difficult task. In addition to the uncertainty associated with future climate projections in key weather variables (e.g. future wind speeds), the high impact of extreme events on the electricity infrastructure may also influence significantly other infrastructures, such as telecommunications and transportation. Thus far, the low probability of severe weather events has made it hard to develop a suitable cost benefit analysis. In addition, large-scale investments for enhancing resilience will require social acceptance of new physical infrastructure and public confidence in energy companies, as well as government policies for attracting investors.
3. Response to Questions This section provides the collective responses by RESNET project to the questions of interest for the specific Call for Evidence.
Short term (to 2020)
1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base?
UK’s electricity system can currently be considered adequately resilient to peaks in demand and sudden shocks, mostly due to built-in redundancy. However, more variable renewable energy sources penetrating the system in the short to medium term may challenge its ability to deliver sufficient generation capacity at peak times with the current level of reliability, particularly if this occurs simultaneously with greater demand through electrification of heating and transport and the addition of new cooling loads. With increasing impacts of climate change on demand patterns as well as on the frequency and severity of extreme weather events, the resilience of the existing electricity network will likely be compromised. To maintain current levels of resilience and wider performance into the medium and long term, measures will have to be taken
174Executive Office of the President, “Economic Benefits of Increasing Electric Grid Resilience to Weather Outages”, USA, August 2013. 175Cabinet Office, "Keeping the Country Running: Natural Hazards and Infrastructure," UK, October 2011. 176National Infrastructure Advisory Council (NIAC), "A Framework for Establishing Critical Infrastructure Resilience Goals," USA, October 2010. 177Intergovernmental Panel on Climate Change (IPCC), “Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation”, September 2012.
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to reinforce, upgrade and develop the grid. Within the RESNET project, a novel time-series simulation based tool has been
developed and applied on a test network for evaluating the resilience of the transmission system to extreme wind conditions178. The frequency and duration of customer disconnections were used as resilience indices of the test system for quantifying the influence of wind. The simulation results show that the test system is robust to the expected range of wind conditions as expected from a well-designed and operated system, but it is less resilient (i.e. significantly higher frequency and duration of customer disconnection) to unforeseeable severe wind conditions. This tool is currently being applied to a model of the UK’s transmission network, which will provide insights on the level of resilience of the system to severe weather conditions and also quantify the effects of resilience enhancement measures.
2. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’?
There are several hardening measures for improving the resilience of UK’s electricity infrastructure to extreme weather events, which refer to structural and topology measures such as undergrounding distribution and transmission lines, upgrading poles and structures with stronger, more robust materials and building new transmission facilities. However, the considerable uncertainty associated with projections of future extreme wind speeds (and in general extremes of weather) leaves serious uncertainty in the estimation of the extent of these measures required to meet possible increased hazard. Whilst it is very unlikely that the future wind and icing regimes in the UK will be as hazardous as those in other parts of the world (such as North America or Scandinavia), there are plausible suggestions that the frequency of occurrence of wind speeds capable of disrupting distribution networks may increase, as has been observed in recent years (e.g. winter of 2013/2014).
Hence, the question arises as to whether it is worth investing in assets to withstand a small number of more severe high impact events, whilst considering that even with such investment the infrastructure may not be able to cope with the most extreme events anyway, or it may be better and more cost effective to invest in operational, “smart” measures, such as demand response and automated wide-area protection schemes for protecting the integrity of the entire infrastructure or strategic parts of it. Recent advances in seasonal weather forecasting might even enable improved preparation and planning for such events. We aim to answer this question through our modelling in the near future.
In the short to medium term, increasing the penetration of variable renewable energy sources could impact on the ability of the system to deliver the current levels of reliability of supply, especially if electrification of heating and electric vehicle penetration increases. This is also to be seen in the light of our recent studies that indicate that traditional analytical approaches to estimate the adequacy of a hybrid renewable-
178M. Panteli and P. Mancarella, “Evaluating the impact of weather on the resilience of critical power infrastructure”, IEEE Systems Journal, Under Review.
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conventional generation portfolio might provide different results relative to more detailed time-series based simulation approaches179.
3. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? Reliability standards and extents of redundancy at different levels of the system have traditionally been set on the basis of an underpinning cost benefit analysis that would take into account the occurrence of foreseeable events. The underlying assumption was that extreme events would be so rare that they could basically be neglected. This approach justifies the current level of security the system is operated with. However, a wealth of research, mostly prompted by extreme weather events in the US, is emerging in the power system community, sufficiently so as to trigger some rethinking of this approach. In fact, the so far low-probability extreme weather events might become more frequent due to climate change, and in addition their impact is so high that measures have to be taken to mitigate the risk of supply introduced by such events. Ongoing RESNET work is using a systematic cost-benefit analysis to weigh the benefits gained from applying several resilience enhancement measures (in terms of reducing the frequency and severity of weather-related loss-of-supply events) against the cost of these measures. This should help future decisions be more informed on the most suitable and economically justifiable measures.
4. What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this?
Our research indicates that more studies are needed to quantify the level of security of supply that a hybrid renewable-conventional generation system might deliver, as well as that reliance on alternative technologies such as demand response and storage to deliver system capacity might be less effective than believed180. In addition, improved climate model projections of extreme winds are necessary to assess and hence ensure resilience to weather related electricity outages.
RESNET research makes clear that even the UK’s domestic mitigation commitments (i.e. around the 80% target) will, during the 2030s, require a grid that can deliver twice as much energy as that of today. However, for the UK to meet its international commitments on climate change (i.e. to make its fair contribution to “stay below a 2°C rise” and in keeping with the latest IPCC carbon budgets), the scale of electrification necessary is far beyond anything yet countenanced. Even with a rapid and major improvement in energy efficiency, the 2°C commitment will likely require a zero-low carbon grid delivering three or more times the energy per year than does today national grid.
5. Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure? Developments in technology, such as energy storage and microgrids, as well as findings
179Y. Zhou, P. Mancarella, and J. Mutale, "Generation Adequacy in Wind Rich Power Systems: Comparison of Analytical and Simulation Approaches," International Conference on Probabilistic Methods Applied to Power Systems, July 2014. 180Y. Zhou, P. Mancarella, and J. Mutale, "Contribution of Demand Response and Electrical Energy Storage to Adequacy of Supply," IEEE Transactions on Power Systems, Under Review.
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from research projects like RESNET, will support the decision-making on the most suitable and economic solutions for improving the resilience of the electricity infrastructure in the near future. This is discussed in more detail throughout this response.
Medium term (to 2030)
6. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience?
To meet the requirements of the UK’s domestic climate change targets there is likely to be a substantial shift to electricity as an energy vector through electrification of heating and road transport. Not only will this place substantial new loads on the grid, but there will also be an associated impact on societal resilience, i.e., people’s ability to go about their everyday tasks, as their means of energy service provision becomes less diverse. Moreover, potential higher temperatures during summer will lead to higher use of air-conditioning by the house holders and businesses, which will introduce a significant new load during summer months. Probably from the late 2020s, this might introduce new challenges on the system, as the power plant fleet will have to operate at higher average utilization throughout the year, which depends however on the future demand profile.
From an operational perspective, work carried out in RESNET shows that changes to the weather conditions experienced by components of electrical networks such as overhead lines and transformers may lead to different extents of de-rating181. This will in turn affect their operational reliability and power transfer capability, and in turn the reliability of the electrical network. De-rating of components will also amplify the challenges in accommodating large amounts of renewables, which requires the full utilization of the existing transmission network and possibly the building of new transmission facilities. This aspect is increasingly important as DECC182 estimates that around a fifth of generation capacity available in 2011 will be retired by the end of this decade and expected to be replaced with renewables. In addition, increasing constraints arising at the transmission level could further reduce the capability to securely and economically maintain the current level of electricity supply. The possible increase in the frequency and severity of extreme weather events makes the picture even more challenging.
As previously noted, in the short to medium term, increasing penetration of intermittent renewable energy sources (localised or not) could impact on the ability of the system to deliver sufficient capacity at peak times so as to maintain the current level of reliability of supply, especially if electrification of heating is undergone. Further challenges are related to operational balancing and reserve requirements, as well as voltage issues particularly for generation embedded in the lower voltage levels. However, localised generation connected to the distribution level could, accompanied by advanced protection and control strategies and possibly improved energy storage capabilities, enable the operation of autonomous islands (i.e. microgrids) during
181X. Hu and I. Cotton, "Impact of climate change on overhead lines operated using dynamic rating in a smart gird," International Conference on Innovative Smart Grid Technologies (ISGT EUROPE), October 2013. 182DECC, “Electricity Market Reform: policy overview”, November 2012.
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electrical emergencies (and in particular the ones associated to weather events), which could help increase the resilience of the electricity network. Ongoing work in the RESNET project will try to address this latter aspect in more detail.
7. What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models?
How future power supply and demand will evolve post 2030 is uncertain, as current mitigation policy could lead to various different low carbon systems. Our research suggests flexibility and extensibility of the grid usage is essential for improving resilience. Flexibility includes curtailment and/or shifting of the demand, together with operational schemes that would be applied following an electrical contingency. Extensibility includes techniques to integrate new technologies/systems, possibly demonstrated on trial projects, to the grid along with storage and distributed generation.
In addition, modelling the impact of severe weather events on the UK transmission network will help inform on the most appropriate and cost effective measures for achieving a resilient UK electricity infrastructure. These do not only refer to infrastructure interventions, but also (and probably most importantly) to the operational emergency measures. Understanding the most significant changes anticipated of the climate will contribute to improved scenarios used in our modelling, which in turn will help provide better and more accurate suggestions for the resilience of the UK network in the future.
8. What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this?
The actual steps depend fundamentally on what role electricity is to play in helping the UK meet either its domestic 80% by 2050 decarbonisation agenda or its much more stringent international commitments around “staying below 2°C”. These very different framings of the UK’s climate change commitments (80% & weak carbon budgets or 2°C and tight IPCC-based budgets) were discussed briefly in response to Q4; for a more detailed explanation see183.
As it stands, current UK policies fall far short of delivering on either the strong (2°C) or weak (80%) framings of climate change. Consequently, whatever the final choice, the electricity supply system, as well as the transmission and distribution networks, require a massive programme of decarbonisation and expansion. Until such challenges are recognised and a quantitatively coherent analysis of the necessary responses developed, any assessment of the resilience of a grid of unknown size and fed by an unspecified portfolio of generators, will inevitably be very coarse. From an analytical perspective, the RESNET project overcomes this by postulating a small suite of alternative decarbonisation scenarios, assessing the resilience of these and drawing conclusions on the basis of this analysis. Once completed, lessons can be learned and implications for the UK’s incrementally changing grid inferred; however provisional findings clearly demonstrate that current policies will not deliver a resilient and decarbonised electricity system.
183K. Anderson, A. Bows, and S. Mander, “From long-term targets to cumulative emission pathways; reframing the climate policy debate”, Energy Policy, 36, pp. 3714-3722. 2008.
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9. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? Energy storage will play a key role in the future for improving network resilience. It is currently a quite expensive solution, which prevents its wide application in the electricity network. However, the developments in technology will help reduce its cost, which will enable the use of energy storage for enhancing resilience. Storing energy locally will help deal with the challenges of distributed generation and will also contribute to balancing microgrids, which will be an effective measure for coping with electrical emergencies on the transmission network.
10. Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system? We need to look wider than technology, and take a more holistic view of resilience and how buildings and their environment may impact on electricity demand, including future demand for cooling. The size of the decarbonised electricity network required to meet future electricity demand, including electrification of services such as heat and transport, has implications for the resilience of the network, and a knock-on effect on social resilience.
11. Are effective measures in place to enable Government and industry to learn from the
outputs of current research and development and demonstration projects? The project is supported by National Grid, which gives us the opportunity to get an industrial perspective of the important issues we are facing. In addition, we believe that better support by and communication with the relevant governmental bodies would help us improve our modelling and make it more applicable to issues and challenges that they may be aware of and that may be of urgent interest.
12. Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? The time-scales that high-impact low-probability weather events occur over are significantly different to the sorts of time-scales that markets are good at responding in. While the current transmission network is relatively resilient, this was mainly developed by the government sector, and while market led industries can consider longer time-scales, the large uncertainty over some key future extreme weather events (such as wind) may prevent them from doing this.
4. Conclusions The UK’s electricity infrastructure can be considered resilient to the current climate conditions, but is very unlikely to be resilient to the future challenges imposed by climate change, especially when changes to both the generation and patterns of consumption necessary to deliver a decarbonised energy sector are considered. Uncertainty in future climate projections makes it difficult to quantify changes in resilience due to extreme
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weather; however, preliminary work in the RESNET project shows that extra reliance on the electricity sector is in itself a cause for concern if the current system remains unchanged. Therefore, measures have to be taken to both hardening the network and improving its operation through advanced, “smart” solutions. Such changes will help build a UK electricity infrastructure that is resilient to future challenges and sudden shocks.
The RESNET project and accompanying expertise offers useful insights on the development of a decarbonised and resilient electricity system, but, as it stands, there remains no evident political commitment or planned route to such a future. If such commitment was forthcoming, expertise of those engaged in RESNET could certainly help guide policymakers and industry in detailing a resilient electricity system commensurate with either the UK’s domestic (80%) carbon target or its more stringent (2°C) international commitment.
19 September 2014
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Resilient Electricity Networks for Great Britain (RESNET) project, the Committee on Climate Change (CCC) and the Energy Technologies Institute (ETI) – Oral evidence (QQ 124-138) Transcript to be found under the Committee on Climate Change (CCC)
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Royal Academy of Engineering and the Institution of Engineering and Technology (IET) – Oral evidence (QQ 1-16) Transcript to be found under the Institution of Engineering and Technology (IET)
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Royal Academy of Engineering – Oral evidence (QQ 150-166)
Evidence Session No. 13 Heard in Public Questions 150 - 166
TUESDAY 16 DECEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Lord Hennessy of Nympsfield Baroness Hilton of Eggardon Lord O’Neill of Clackmannan Lord Patel Lord Peston Lord Rees of Ludlow Viscount Ridley Baroness Sharp of Guildford Lord Willis of Knaresborough Lord Winston ________________
Examination of Witness
Dr John Roberts, CBE, FREng, representing the Royal Academy of Engineering
Q150 The Chairman: Welcome, Dr Roberts. I am sorry that we kept you waiting a while. We were deliberating on our future report. Thank you very much for joining us today. I know that you join us very much as one of the co-authors of the recent RAE report Counting the Cost: The Economic and Social Costs of Electricity Shortfalls. We will hear, I am sure, during the course of the questions, about some of your findings. Indeed, we have had an opportunity, of course, to read the report. For the record, we are being broadcast. Would you like to introduce yourself, and if you would like to make any opening statement, do please feel free to do so.
Dr Roberts: Thank you. My name is John Roberts. I am a fellow of the Royal Academy of Engineering and have been since 2005. I worked with colleagues in the policy part of the Royal Academy to produce the report. Perhaps just to set it into context, if I may, in May 2013 we were requested by the Council for Science and Technology to produce a report on the supply capacity margin: in other words, the extent to which the supply of electricity will exceed demand. Our report was submitted to the CST in September last year and published in October.
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Essentially we said that the margin by which supply would exceed demand was going to narrow very sharply, and we made some recommendations as to what the Government and the industry could do to mitigate some of those effects. Those recommendations were largely taken on board and put into place. As a consequence and a follow-on to that, in July this year we were asked by the CST to do almost a codicil to that report and to look in theory at what would happen if we actually had a shortage of electricity supply in the country and we had to have substantial outages. That was the substance of our report that you have mentioned, Counting the Cost. We did desktop research, we did workshops, we spoke to people in the industry and we have produced that report.
Q151 The Chairman: Thank you very much. I think we will be particularly concentrating on what you call the codicil rather than the original report of two years ago, and I recognise the difference. Your second report is not so much about the likelihood of disruption but about the potential cost of disruption. That we appreciate.
Let me ask a very general question to start. Could you tell us what the economic and social consequences are of interruptions to the electricity supply, and particularly to what extent electricity outages resulting from a shortage in capacity and an external shock to the system differ in their consequences?
Dr Roberts: I think they differ in a number of ways. Clearly, if there is an external shock to the network, a system storm or whatever, and there is a lack of available capacity, the net result is the same: there is no electricity. But the nature of those impacts on the system is quite different. If we had a shortage of generating capacity, that would be reasonably predictable and therefore could be planned for ahead of time, whereas outages, which would normally affect either the transmission or more likely the distribution systems—the wires—as a result of storms tend to happen very suddenly. You may be able to forecast a day or so ahead, but when they impact you are never really certain where they are going to impact. As we have recently had up in Scotland, tens of thousands of people can be off supply for maybe 48 hours. Those interruptions are less predictable. You can plan in general terms for them, but you cannot plan for them specifically. I think that is the fundamental difference.
The Chairman: How would you characterise the difference between planned and unplanned?
Dr Roberts: If you know that there is going to be a shortage, you can take steps to mitigate the impacts. For example, you can request power stations to maintain generation rather than switch off, you can communicate with the public, you can invoke arrangements with large industrial users to reduce demand and you can generally communicate with the public and alert them to the fact that there may be outages. In particular, the effect of an outage differs over time during the course of the day. Loss of power at night clearly does not have a huge impact on residential consumers, whereas loss of power, say, at 8 o’clock in the morning or 6 o’clock in the evening when people are coming home, putting lights on, cooking food and so forth, can have significant consequences. So by a combination of asking power stations to continue generating or by asking large industrial users to diminish their load at times of peak, you can mitigate the effects. You can peak lop, you can shift load, so you can minimise the actual impact that it will have.
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Q152 The Chairman: One of the interesting observations in your report was that when people were asked about how they valued the prospect of a loss, the thing that they seemed to be most worried about was loss of data, the computer going down. That could be one second or several hours, but the effect would be the same, so duration of the outage is not necessarily a critical factor. Is that correct?
Dr Roberts: Duration can be. For individuals, for people with computers, as you rightly point out, a short break in supply can have the same damaging effect as a lengthy outage, but particularly in the case of manufacturing large industrial consumers may well have some resilience. They can get by; they have standby generation and so forth. They can get by for a few hours, but if an outage lasted, say, for 24 hours, the effects could be very damaging. So duration is an issue, as is frequency. People may not like the loss of supply once a year, but they would get over it, but if they had frequent losses of supply, that would be quite different.
Lord Winston: You mentioned mitigating partly by informing members of the general public. I am not sure that I have declared an interest as an honorary fellow of the Royal Academy of Engineering, but I wonder how effective you think that is and how effective communication with the public will be in the event of outages or reductions.
Dr Roberts: I think it is to be tested in practice. That is the point. We have not had an issue of predictable outages since the three-day week in 1974. If you look at what happened in Japan after the Fukushima earthquake when they had to shut down all their nuclear power and they had a severe shortage of power, they mitigated the impacts quite significantly by very effective communication with the public in Japan. Whether that would happen in this country, frankly, you would have to find out in practice, but in general terms if the public are informed of what is happening and why, they tend to react more favourably than if things just happen out of the blue and they get no sense that anybody knows what is going on.
Viscount Ridley: On this question of duration of interruption, I think that in some ways we are more resilient now, because if the electricity went off now I would not lose anything from my iPad. Indeed, that is the way I operate at home. I am now on a laptop and no longer on a PC. I would get several hours on my telephone before it ran out of battery because it is a mobile phone, and even then I could get in my car and drive around in circles just to charge it. I have never done that, I promise. In other words, certainly as consumers we are not quite as pole-axed by a short-duration interruption. Indeed, I do not even need the light on, because I can read my books on my iPad. Is that true for industry as well?
Dr Roberts: I think this question of duration is very important. Compared to where we were in 1970 with the three-day week, we are obviously so much more reliant now on electronics and electrically-driven equipment. For industry, a lot more supply chains are now a lot less resilient. The financial services industry, for example, is hugely dependent on computing. When Hurricane Sandy hit Manhattan a couple of years ago and that was flooded, everybody’s standby generation kicked in but then they ran out of diesel and they could not get the diesel into Manhattan because it was flooded. That was an issue of duration. They could manage for 24 hours, but beyond 24 hours they could not. I think it will impact different industries in different ways.
From an individual point of view, yes, my mobile might last for a short time. It depends on how resilient my mobile network supplier is and whether they have standby generation as to whether their network is going to work. I mentioned Fukushima. When the Fukushima issue
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hit, the mobile network in Japan collapsed, partly because it was inundated by people trying to make mobile calls but also because they did not have sufficient resilience.
Then again, everybody’s central heating, even if it is gas, will not work without electricity. Maybe you do not mind having no central heating for a day or two, but after that it gets to be a bit tiresome, particularly in the winter. The point I am trying to get to is that modern life is just so dependent now in so many ways on electricity that loss of electricity for more than 24 hours is difficult. In this country we are so used to the fact that we have a very high degree of security of supply that not many people ever think about doing anything to mitigate it.
Lord Hennessy of Nympsfield: Do you think there is anything that we can still learn from the three-day week of 1973, 1974? The folk memory in so far as it exists is that with television going off at 10.30 pm the Government’s popularity plummeted and the birth rate shot up nine months later. That is how people remember it, if they remember it at all. I remember that at the time there was a lot of talk of people rather remembering the war—a very high proportion of the population could still remember the war in the early 1970s—and being jolly with each other and talking on underground trains and so on, and the level of production held up remarkably well. There was a kind of feeling that there was still a considerable residual stoicism among the British people. Since then we have had a lot of studies that Maurice will know about, JK Galbraith and others, about the growth of a culture of contentment and how people get very jumpy very quickly if any of their normal supplies and services are jeopardised even for a few hours. I know you are not a social scientist, and perhaps that makes you even more qualified to talk about this, but do you think there has been a change in British society where people get rattier quicker?
Dr Roberts: I can remember the three-day week, because I was a very junior engineer in those days, and I was phoning people—I was based in Chester—telling them that they were going to be off supply for three hours at a time, and you are right that there was a degree of stoicism. It was not that long after the war. I think somebody characterised it as people moving from being consumers to being citizens and they think about banding together. My sense would be that if you look at what happened with the floods in the Somerset Levels and things like that, the public have a relatively lower tolerance level now. For the first few days it is interesting and life is a bit different. It is not quite a game, but it brings a society together and people exhibit the British spirit and all that kind of thing. That is great for three or four days, but if it carries on beyond that somebody starts to say, “Who on earth is charge here? Why is this still going on?”. I think that tipping point is reached probably more quickly now, going back to the point I was making before, because we are now so dependent on electricity. If you go back to 1974, if you wanted to get money out of the bank you went into the bank, handed a cheque in and the man gave you some pound notes. Now we all use ATMs. There would be no ATMs. How would we manage with that? You cannot send the children upstairs to play with their computer games any more—all those sorts of things. As you say, I am not a social scientist, but my own view would be that life would change very sharply and that a lot of conveniences that people take for granted would not be there. I think that after a relatively short period of time someone would start asking questions, pointing fingers and seeing who is responsible.
We had the Christmas storms last Christmas on the south coast. It is interesting—and I know this from personal experience—that if there is a supply outage even due to a storm on Christmas day, people regard that as almost an insult, that somehow you know it is
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Christmas so why have the lights gone out, and they get very angry, very quickly. So my answer would be—I would not like to see us testing it in practice—that people would get very frustrated sooner than they would have done in 1974.
The Chairman: This is where I always have to declare an interest. I certainly lost my cool last Christmas day.
Q153 Lord Willis of Knaresborough: That is the third time you have reminded us of that.
When we began this inquiry we had a simple explanation that with supply over demand there was 4% resilience in the system, and that was adequate and there were back-ups even if that 4% disappeared. It struck me that when the bank stress tests were announced this morning, the scenarios that they were incorporating into those stress tests were significantly more severe and significantly more sophisticated than what was happening with electricity, and yet electricity is at the heart of making sure that our banking system is resilient as well. When you were doing the report and the codicil, did anybody in government or elsewhere apply stress tests of that magnitude to the resilience question? If so, who were they and where is that evidence?
Dr Roberts: The answer is yes. The evidence is in the first report, the one I mentioned that we did the year before, because among other things I am involved in the financial services industry. I am chairman of a bank. When we did our report, I imported stress testing from my financial services experience. We looked at a 4% margin and then applied the kind of stress testing that you would apply in banking circles, which is to say, “Let us look back over the last five or 10 years and look at real events that took place that would really stress the system”. We looked back at December 2010, I think it was, when we had 10 days of very cold weather and no wind, so that none of the wind-power renewables operated at all. We also looked back at May 2008 when on one single day, in a completely unconnected way, two major power stations, Hinkley and Longannet in Scotland, had operational problems and had to shut down on the same day, which caused a huge disturbance in the system. We asked whether, if that happened in the middle of winter when it was very, very cold—a day like today—and no wind, the system would survive. The answer was that it would be a very, very close call. That is incorporated in our report.
We said that at a 4% margin, technically speaking you would get by statistically but the resilience of the system was sufficiently eroded that the longer it went on, if you had two or three really abnormal incidents coming together at the same time, we could be in trouble.
Lord Willis of Knaresborough: But I would like to know whether the tests that you applied over that 10-year scenario the Government are applying as well. The tests that you applied over that 10-year period were unique over that 10-year period. If Japan had done the same over the 10-year period, that period would not have had Fukushima in it, because the idea of a tsunami hitting and knocking out its nuclear power stations I suspect was not there. Certainly John Beddington reported that that was not the case. I just wonder about going to that extra level, because the bank stress test, from what I was reading this morning, seems to have gone significantly beyond what a normal series of events would be.
Dr Roberts: The stress test that we did took account of real world events that really did happen and demonstrated that the system would be right on the verge of losing its stability. We could have envisaged even more extreme stress tests, but had we done so all we would have demonstrated was an even worse situation. I think that what we demonstrated to our
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satisfaction was sufficient to say that the Government should be aware of this and that National Grid should take steps to improve the resilience of the network. To have gone further would have been to emphasise the point even more, but I take your point.
Q154 Lord Rees of Ludlow: The loss of supply is probably predictable in the sense it is a Gaussian distribution and you can work it out, whereas I would have thought that the distribution network is vulnerable and you might imagine that there is a long tail of a small chance of some really catastrophic effects to the wider network. Do you think that is something that we should worry about more? In that context, do you think we are spending enough on the resilience of the distribution network and on back-up generators for elevators in skyscrapers and things like that, without which a city could not survive for more than a few hours?
Dr Roberts: I would distinguish between resilience of the generation side of the system and resilience of distribution.
Lord Rees of Ludlow: The latter, one suspects, might be less Gaussian and a bigger chance of a long tail.
Dr Roberts: Yes. I think we are spending a sufficient amount on the distribution network. We have just completed the price review for the distribution network with Ofgem, and that will come into effect on 1 April. I think that makes sufficient allowance for investment in the network to maintain the resilience of the network. As far as the supply is concerned, I would have the concern that the supply margin is quite small now. On your point about a Gaussian distribution, I think what we are worried about are the Black Swan-type events that suddenly happen and whether we have sufficient generation. I would argue perhaps that we do not, but—and this is, I think, the core of the report that we have just produced—we do not really have a good sense of what the costs would be if we did have those sorts of outages: hence, we do not have a benchmark against which to judge how much we should spend, because system security comes at a price. At the moment the public at large are very sensitive to electricity prices, almost to the point, I think, where they say, “I am paying this much a year for my electricity. I expect you to make sure that it is there all the time. That is what I am paying for, am I not?”. Saying, “No, you have to pay some more now to make sure it is there”, might not go down very well, even though it may be entirely justified in technical and economic terms.
Q155 Lord Peston: The general rubric of the questions that we are asking you uses the phrase “economic and social consequences”. More or less everything you have said, to my ear as an economist, sounds like economics. Can you tell me where we draw the line between economic and social policy purposes?
Dr Roberts: That is difficult. “Social” in the narrow sense would be the impact on domestic consumers, where there is not necessarily an economic impact but simply the inconvenience factor, but in a very large sense. Beyond that, if there were economic impacts of an inadequate or unreliable electricity infrastructure, that could then result, for example, in a lack of direct inward investment and the UK getting a reputation of being an unreliable place to site factories. That in turn could clearly have social effects, because of what it would do in terms of GDP and employment and so forth.
Lord Peston: Yes, but you define “social” simply as households, whereas in social science that would not be what most would have thought you would have had in mind. They would
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have thought that you would discuss inequality: namely, whether the rich get hit more or the poor, or particular social groups such as the elderly, particularly those who are at risk medically. Do you have any cognisance of any of those effects? To take an obvious example, I gather—happily it does not yet apply to me—there are elderly people who do have medical problems and they have a button that they can press to get an immediate response and attention, which may save their lives. I assume that that button depends on having some electricity. Should not someone be looking at that kind of question when we ask what the right amount of capacity is, both generation and distribution, within our society? Some of us would not give a damn if the City of London—I have said this before—could not operate for a few hours, but we would certainly care terribly if an elderly relative died as a result of their button not working?
Dr Roberts: Yes. As the Chairman said, I am not a social scientist.
Lord Peston: No, but I am just wondering from your experience what you expect.
Dr Roberts: In my experience, first of all, at the local level with distribution, vulnerable customers are known to the local distribution company, so they know if there are people who have problems and they can sometimes do something about it. The problem would be if you have major outages. I think the scenario that we are talking about here would be national rolling blackouts. In those circumstances I do not think that the local distribution companies would have the resources to deal with that. If there is a local outage because of a storm, they know where the vulnerable customers are; they have standby generation that they can bring into effect. But if we were, as we were in 1974, switching people off in large blocks, that would not be possible. Within that, though, significant installations like hospitals would be kept on supply, because they have dedicated supplies. But if we are talking about the people you mentioned, vulnerable residential domestic customers, that would be very difficult. I quite take your point. I do not think that I am adequately informed to comment on it.
Lord Peston: No, but would you agree that it is not a question we can neglect?
Dr Roberts: It is a very important issue, I exactly agree.
The Chairman: To be fair, in your report you do deal with some of the specific social and psychological issues, do you not?
Dr Roberts: I think we made the observation that in those circumstances one would hope that local communities would come together, that that social side of the issue would be addressed, but clearly it was beyond our terms of reference to make any recommendations on that.
Q156 Lord O’Neill of Clackmannan: I was interested in what you said about the stoicism, almost, of the Japanese people. I was in Tokyo on the day of the tsunami and it was quite clear that nobody knew how serious it was. Nobody knew it was 9.3. They just knew that it was a big earthquake, but there was a sense of awareness that the public—there are 200 earthquakes a year in Japan. The public are trained from school age to take account of potential problems. So the first thing I would want to ask you is whether you think that we should be trying to explain to people that we are potentially vulnerable, without being accused of scaremongering?
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Dr Roberts: I take your point about the Japanese and earthquakes. The point I was trying to make was that because they then decided to shut their nuclear stations down and had a shortfall of electricity generation, and because they communicated that very effectively, I think they managed to cope with it quite well. From our point of view writing the report, what that pointed to was the importance of clear and sensible communication from the centre.
When we wrote our report last year and made the observations about the potential narrowness of the supply margin, we were saying in essence that certain things had to be done. That report got quite a bit of coverage in the media. I think it is a fine line between making people aware of the issues and scaremongering. For me, the most important point is to make the public at large aware of the fact that we need to make substantial investment in our electricity infrastructure. Apart from the decarbonisation point, which I put to one side, simply put we have an infrastructure that is ageing. Many of our power stations were built in the 1960s with an economic theoretical life of 30 years, which is now well exceeded. Ditto a lot of our distribution networks were built in the 1960s, again with an economic life of 20 to 30 years. So we need to invest a lot of money in our network as a whole to make it more resilient, and we need to communicate that message to the public at large: they may not like it but electricity is going to get more expensive if you want to enjoy the level of resilience that you have enjoyed to date.
Lord O’Neill of Clackmannan: You mentioned the case of the Manhattan financial services running out of diesel. Do you think that the National Health Service, or for that matter the railway companies, are aware of the need for support generation on perhaps a potentially longer period? Do you think there is a consciousness of the threat to essential services by the providers of these services?
Dr Roberts: I cannot speak with any knowledge of the health service or some of the others. I can only speak with knowledge of the financial services sector. I think that everybody thinks that 24 hours is about enough, so to have the capacity to run for 24 hours is sufficient and within 24 hours somehow or other everything will be all right again. That I think is potentially unrealistic. When you think of how much money is at stake if the computers shut down in a large bank, we are talking billions if not trillions. Look what happened when Lehman’s fell apart. There is a huge amount of trades out there. It would be chaotic. When you talk about resilience and back-up, I do not honestly believe that anybody really thinks much beyond 24 hours.
Lord O’Neill of Clackmannan: The consequences of that for investment would appear to be dire if we were in a worse position than other countries. We are obviously more vulnerable because we have a higher dependence on financial services, for example. To what extent did you pay any attention to future investment in the UK? You mentioned it en passant but you did not put any figures to it; you did not put any forecast. Could you be a bit more explicit there, please?
Dr Roberts: Sure. We spoke to a number of industrialists about resilience and security of supply. Putting it in qualitative terms, not quantitative terms, they basically said, “Whereas a few years ago we would have taken security of supply as a given and we would not even think about it, now it is an issue and it is coming up the agenda”. A number of companies that we spoke to had done surveys to look at cost benefits at each of their sites to work out whether it is beneficial to incur the costs of putting in back-up supplies, because what would
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be the cost of an outage. My sense would be that we have had a number of natural disasters over the past few years with floods and storms and whatever, and industrial consumers are very aware of the fact that many supply chains now are very thinly stretched. Everybody works on “just in time”, so they need to think very carefully about making investments to make sure that they have their own resilience. That is certainly coming up the agenda. We could not put numbers on it, unfortunately, but what was interesting to me was that if we had conducted those interviews 10 years ago, it would not have featured at all.
Q157 Lord Dixon-Smith: I always have difficulty with this sort of subject because I have always regarded the electricity industry in two ways. The actual supply is not a stream, as far as I am concerned, it is a lake, and you have to keep the level in the lake high enough. By and large, that side of the industry works extremely well. But the interruptions come almost entirely on getting it from there to the customer, most of which are, of course, as a result of natural events about which we can do nothing, and can occur at random and very unpredictably. I did find myself wondering whether in fact one could overcome some of this difficulty by a greater use of interconnectors, which can, of course, bring in supplies from outside. However, if the problems are largely local, that would not really help very much. I wondered if you could comment about that as a possibility.
Dr Roberts: Yes, that was something we looked at in our first report that we produced a year ago. There are four gigawatts of interconnection between us, the continent and Ireland. The problem is that the electricity that runs on those interconnectors is subject to purely commercial contracts. If, for example, we had very cold weather here in the UK but equally cold, or even colder, weather in continental Europe, commercially it would make more sense to send the electricity to France than it would to keep it here. Interconnectors have their use, but only up to a point.
I take your point. In theory, since we have been part of the EU the whole of Europe we are supposed to be more interconnected, because in the long run that would be economically beneficial. However, you just get involved in kinds of national interests and so forth, and that really has not happened to the extent that it should.
Lord Dixon-Smith: That gives rise to a slight secondary question: are we right, either in the short term or the long term, in regarding ourselves as an “island”, as we historically are, in a world that is increasingly interconnected?
Dr Roberts: I think the theoretical answer, if you like, is that we should be more interconnected, because by definition that spreads the risk. But the commercial aspects of that are probably more difficult, because obviously it is very expensive to lay submarine cables to connect us to other parts of Europe.
Q158 Lord Broers: I would like to ask a general question, which is partly a social question, and to address some of these issues. Industry as a whole is sophisticated in its use of electricity. The normal consumer is not. The market has not really developed as it has in other places, for example in transport. We all remember the day when the price of an airline ticket between here and New York was a fixed item. Now we know that it changes by the minute and by the hour. The insurance industry is more sophisticated. After all, what we are talking about here is really insurance. You know when you buy a car policy that if you take a larger excess you will get a lower premium. You can insure more or less just your windshield, or not. All of this could happen in the electricity market. The individual consumer could
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decide that they would be perfectly willing to accept outages at certain times of day. They would be quite willing to accept a long-term outage, prepare themselves for that, and balance that off against a reduction in cost.
I notice in the States now that a lot of my perhaps more wealthy friends have put huge gensets in their houses. I know lots and lots of people who have now done that because they are not going to have a large outage and they can balance it. It costs them $25,000 to put that thing in. They will put it in because they just do not want to be left for weeks, as they have recently. Did you look at the potential for a dynamic market like that, because it could reduce costs potentially, and it could increase resilience?
Dr Roberts: We touched on that in the report. That sophisticated time of day pricing needs smart meters. At the moment we do not have the information, and the suppliers do not have the information that would enable them to have that kind of sophisticated pricing. We mention in the report that our intention is to roll out smart meters across the country by about 2020. When everybody has a smart meter the electricity companies will have that information and they can put the pricing in place, which will give people much clearer signals about the way the price of electricity varies across the course of the day. Then they can take steps if they want to avoid high price electricity, and by extension even to the point that you suggest: that they put in their own generation as an insurance against outages.
I come back to the basic point that I made a bit earlier, though, that most people at the moment regard what they pay for electricity as more than sufficient to make sure that they get a 100% secure supply. There is an educational process that has to be gone through to get people to the point where they would be prepared to make a personal investment in some sort of standby supply. Certainly, having smart meters and more information means that in turn you can communicate with the individual consumer and explain to them what the cost of the usage is and how best they can manage their actual consumption to get the lowest overall cost of electricity.
Lord Broers: Are you concerned that those smart meters will in fact be able to do those things? Are we going to get an overall standard that is satisfactory?
Dr Roberts: The meters per se will not be able to do that. What I think we will have available to us is a volume of information that presently is not available. In part, from a computing point of view, it will be a systems integration exercise to put the systems in place in the electricity companies that enable them to analyse the data and to have the sophisticated pricing that you alluded to, for example with iPhones now and so forth, compared to how we used to be with black Bakelite telephones, where the pricing was absolutely uniform. Now it is a lot more sophisticated. I think we will move to that position. That will be for the supply companies. As far as the distribution companies are concerned, the ones that own the network, I think that will be a bit further behind, because at the moment our pricing is universal. It is sort of postage-stamp pricing. Every customer pays the same for the distribution business.
Lord Winston: I wonder whether anybody had made a national inventory of the emergency power that is available for places like hospitals and other organisations, and whether or not that might be a good thing.
Dr Roberts: It would be a good thing. Nobody has done it. It is starting to happen. There are commercial organisations out there now that are in contact with large organisations. For
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example, some of the big supermarkets all have back-up generation in their stores. Aggregating all of that, they can sell that to the electricity generators as an amount of back-up generation that could be available, and that can be sold to the generators as an economic proposition: “You pay us the money and we can bring this back-up generation into play”. It is beginning to happen on a commercial basis. But some kind of index or database right across the UK of the back-up generation to my mind does not exist, and it would be a very useful thing if it did.
Lord Winston: Would it be worth this Committee suggesting that?
Dr Roberts: I think it would be a sensible suggestion, yes.
Lord Winston: Okay.
Dr Roberts: I think that the responsibility should lie with the electricity distributors or with National Grid, or both, maybe with Ofgem overseeing it. It is the kind of information that we simply do not have. If there is one message that comes out of our report, it is that we just do not have the information about any of these issues that we should have.
The Chairman: Thank you. That is helpful.
Q159 Baroness Sharp of Guildford: I am thinking about last weekend's failure of NATS. One can see the chaos that can result from a computer failure if they do not have the standby generating capacity. Obviously they have standby, and as you were saying even the supermarkets have it. Last week we heard about what was happening in the American market and the PMJ Group, which has, as you were suggesting, this smarter system. Are we not developing that smarter system through the capacity market? Is this not precisely what we are trying to do by the introduction of these new market systems into the electricity market?
Dr Roberts: It is one of a number of measures. I think what was deficient before with the economics of the electricity system was that it never rewarded capacity. It assumed that generators could earn enough money simply by generating electricity and selling it to reward the investment. But recognising the fact now that we have more and more renewables, particularly wind power, which is intermittent by its very nature, there was nothing in the economics of the system to reward generators for owning generation and just having it available for the days when the wind did not blow. That is one of the measures that is moving in the right direction. Smart metering will be another one.
Baroness Sharp of Guildford: The two come together, really.
Dr Roberts: It all needs to come together. Sometime out there, maybe five or ten years down the line, we will have a far more sophisticated, information-driven system. We will have what people conventionally refer to as “smart grids”, although what exactly constitutes a smart grid is open to debate. We certainly need to move from a system that is essentially passive at the moment, where electricity generating just flows, to one that is actively managed. That is a big transformation. I think back to the point that I was making earlier about the need to invest in a more modern, resilient system. That is going to be a significant amount of money, and that will have an impact on the price of electricity in the short run.
Q160 Lord Broers: I congratulate you on the report. It is a very comprehensive compilation of everything that one could put ones hands on. At the same time, it leads to a series of
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questions, and these are my questions. Are current methods for quantifying the cost of electricity outages, particularly the value of lost load, fit for purpose? Is value of lost load still a good indicator, and how does it compare to the alternatives? How uncertain are VoLL figures? To what extent can uncertainties be reduced? Finally, what are the risks of basing policy decisions on VoLL, for example decisions about capacity procured through the capacity market?
Dr Roberts: A number of questions. I will try to give you a broad answer, and then, if I have not done enough, perhaps you can tell me. Value of lost load is the conventional measure of trying to put some kind of economic value around interruption of the supply, and as the report says there are two basic ways to do it. You ask people, “How much would you pay to keep your electricity supply on?”, or alternatively, “If your electricity supply was disconnected, how much would you require by way of compensation?”. You get two slightly different answers.
I think the problem in this country is that the vast majority of people have not experienced a long-term supply interruption. When you ask them what value they would put on it, it is a very subjective answer that is in no way grounded in experience but is purely subjective. As we have been discussing in the course of this morning, the actual economic and social impact of electricity outages varies hugely with time and frequency. Just asking somebody, “If your electricity was off for an hour, what would it cost you?”, is, I think, not a hugely revealing question.
There are other ways to approach this, particularly, as we say in the report, through revealed values, which you get by looking at such situations that we have talked about. There was the Japanese experience. There was the Californian experience in 2000 when they had extensive blackouts. That cost the Californian economy $40 billion, as well as a ratings downgrade. If you look at real events and do the analysis post-event, you get a far better understanding of the economic impact, which is perhaps slightly different from the individual customer's perception of what they think it is worth. It is a way of thinking about the cost of the loss of load.
I think we need to do a lot more research. Very little research has been done in this country, as our report points out. There has been one Ofgem inspired piece of research, which was done by London Economics in 2013. That is the only piece that we could find in this country. The rest of it has been done elsewhere in western Europe. We do need to do more research: a combination of trying to establish what the cost would be for individual consumers, small businesses and large businesses, but also looking at what has happened in the real world—at the significant events that have happened elsewhere, both in Europe and in other parts of the world, and after the event to get a hard database of evidence.
The capacity mechanism that is taking place today will go some way to give us another answer, although I think the answer that it is going to reveal is more about the cost of building generation rather than the cost of not having electricity. But it is all part of the overall economic case, if you like, for investing more in generation to increase the supply margins. I hope that has answered your question.
Lord Broers: Yes, I think it has. I suppose what you are saying is that there is nothing wrong with the concept of value of lost load. It is a matter of whether you have the right value for it in the right circumstance. We have heard from some economists like David Newbery that this is all being overpriced.
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Dr Roberts: The numbers that you get out of it are an order of magnitude different from the actual cost of electricity if you buy it, and I think that is to do with perception and the point I was making: that most people have never really experienced a significant loss of supply, so they just try to imagine what they think it would be worth to them. Value of lost load is often presented as a single point number, but it is actually a range of numbers and a range of values. When somebody does system planning and looks at the economics of investing more in energy security, they need to have that range in mind and not really think necessarily of a single point number, because that could be slightly misleading.
Q161 Viscount Ridley: You have made the point very eloquently that we are much more dependent on electricity than we were in the days of the three-day week, and that we would suffer a lot more if we lost it. Is there a risk that government policy going forward in two ways makes this problem even worse? On the one hand, it commits us to intermittent sources of electricity that are much more dependent on the weather, so it increases the risk of problems, and on the other hand it commits us to moving heating and transport on to electric. In the future, when I wake up to find that the lights have been off all night and I need to charge my phone, I cannot even get in my car and drive it because it is an electric car. Is that a problem? Is the electrification of transport going to make our dependence higher and our resilience lower?
Dr Roberts: I think your question exemplifies what is known as the “trilemma”, which is that there are three key issues here. One is security of supply, one is green supply, and one is price. The reality is that you can have one or two, but not all three, and it is all a trade-off. We are committed by law in this country to reducing the amount of carbon in our economy as a whole by 80% by 2050, which implies the sort of things that you have just been talking about. If we want to have a decarbonised electricity infrastructure, the choice, certainly if you get towards 2050 and the 80% target, is that you use hydrocarbons either for heating or for transport, but not for both. That then implies you have to have electric transport and that you need to invest more by way of security, particularly given that, as you rightly point out, as we decarbonise we will introduce more and more intermittency into the system. What then follows is that the third point, which is the economics of supply and having cheap energy, does not exist anymore. That is an expensive solution, and that, I think, is outside of my realm. That is a policy solution for politicians, not for a simple engineer like me.
Lord Rees of Ludlow: Just going back to the value of lost loads criterion, would you agree that that probably underestimates what people are really prepared to pay, first because of the reasons that Lord Ridley suggested, but also because if people are asked what happens if we lose electricity, they think of losing it in their house? They do not realise that they will have a personal loss if it cuts the transport, the deliveries to supermarkets, and all those things. For the individual, surely the downside is far greater than just losing it in their residence. They probably do not think of that when they answer your question.
Dr Roberts: I think it is fairly debateable. It is very much down to perception. An interesting study was done in Munich a few years ago that followed on from a big outage in the city of Munich. They found that before and after, people's view of the value of lost load went down because they found that it was not as bad as they had thought it was. However, there have been other studies in different situations, for example in Norway, where exactly the opposite happened: it was a lot worse than people expected.
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What I draw from that is that it is highly individual, highly perceptual. Yes, I take your point. I think most people would think about not being able to watch “Coronation Street”, but they would not think about the ATM and their mobile phone not working. That brings me back to the point that the interconnectedness of our entire society makes some of these value of lost load estimates highly suspect. I think the real answer is a lot bigger.
Q162 Lord Patel: My question mostly concerns our understanding of the economic and social impacts of the interruptions to electricity supply. The last three questions touched on some of it, but my key ones are these. How good is our understanding of the social and psychological impact of interruptions? To what extent is it possible to learn from other sectors, such as transport? Lord Ridley covered some of this. How will the changes in the electricity system, such as the electrification of heating and transport, affect the impact of disruption? And are there any international comparisons that we can learn from?
Dr Roberts: The first thing I would say is that our report tried to deal with the hard engineering and, to the extent we could, the hard economics of loss of supply. We did not feel able or qualified to talk about the social impacts. Trying to draw comparisons from loss of other essential services in the UK, such as transport, is not particularly representative. Just to come back to the previous question, I think I could live without the Tube, or buses, or a train more easily than I could live without electricity, because of the things we discussed about the interconnectedness.
Your point about international comparisons is well made. We looked at six examples in the recent past of losses of electricity on a substantial scale in what you might loosely call first-world economies. What is clear from that is that the effects are substantial. The economic impacts are much bigger than one would expect. We did not look at the social side of it, and we found that there has not really been an enormous amount of analysis of those events after the fact. What people tend to look at is why it happened. What was the engineering explanation, rather than what were the economic and social consequences?
The best study that we looked at was California in 2000, which is mentioned in the report, when they had a very hot summer, everybody turned up the air-conditioning, and for a variety of reasons to do with the regulation of electricity and the environmental protection laws in California, they just did not have enough generation and the whole system collapsed. It took them several months to get it straight. That cost the Californian economy $40 billion, and that impacted on only one and a half million people. The Californian State took a ratings downgrade.
Now, if you think of the impact of that on the cost of funding and what in turn that would mean for the voters in California, it is quite significant. We need more of that sort of analysis and information from those kinds of international comparisons to formulate a better view for ourselves. We do not have it at the moment.
Q163 Lord Hennessy of Nympsfield: Do you have in your head, Dr Roberts, your own personal version of catastrophe theory, of the very worst that could happen to our beloved islands in terms of electricity supply and the knock-on?
Dr Roberts: Honestly, no. Having lived through the three-day week and been part of it, if you like being involved in it, I think it is common place to observe that in fact the GDP of the country improved because everybody really pulled together. To be honest with you, the
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closest I can get to that is thinking abut what it is like just to have a normal outage that maybe lasts for a few hours, and how utterly inconvenient and awful it is.
The one thing that we have not touched on, and the one thing that we found in our report, was that there was only one incidence of social unrest following a major outage, and that was in Brooklyn in 1970. The analysis that we looked at assumed that it was more a reflection of underlying social issues rather than the loss of electricity. My belief would be that even in the worst case scenario we would find a way back within a few days—fairly quickly. Beyond that it is verging almost on the unthinkable.
Lord Hennessy of Nympsfield: The studies about the three-day week that were done in Whitehall are, I think, declassified now. If I remember rightly, another couple of weeks and we would have been in real trouble. We were getting to the rim of all sorts of knock-on effects, and so the jollity—the “put out more flags” feeling—would have dissipated, as you said earlier.
Dr Roberts: It could have done, yes. On the social unrest aspect, if you talk about worst nightmares it would be the fact that the police force and so forth, the powers that be that would keep law and order themselves, would be severely disabled by the lack of power. Then I think it could be an horrendous scenario.
Lord Willis of Knaresborough: Chairman, may I just follow on from that? Having said that, do you feel, therefore, that the 4% margin is insufficient?
Dr Roberts: I think Lord Hennessey was posing a slightly different question.
Lord Willis of Knaresborough: Under his doomsday scenario, every nuclear power station goes out, it is the coldest day of winter that has ever been, and it follows on from floods. We have an awful lot of things, and Nigel Farage is Prime Minister.
Dr Roberts: And Liverpool has been relegated. To try to put that point into context, I go back to the report of last year and the point that at 4% you are really skating on thin ice.
Lord Willis of Knaresborough: Right.
Dr Roberts: There is not the resilience in the system. Terms like “you could get away with it” are a bit emotive, but I think we are at a point where there is not that much resilience in the network, in the system, to shock events—the kind of thing we have talked about. They would be one-off events, but the longer 4% persists the greater the likelihood that something would happen that cause severe disruption. Therefore, we need to invest and move away from 4%, but it will be at a cost. That, again, to go over ground that we have already covered, is a question of the political will to do it and the acceptance by the public at large that it is worth paying that price. I am not sure that we are there at the moment.
Lord Willis of Knaresborough: We have only had one witness, Dieter Helm, who has argued of a greater margin. Somewhere between 15% and 20% were the figures he gave. Is he in the right ballpark?
Dr Roberts: I know Dieter very well and I respect his opinions. I think 15% to 20% is probably on the high side, and it very much depends on how that is expressed. In the past, we have talked about a 20% margin, but it very much turns on how much reliability of supply you attribute to renewables. Take wind, for example. You can take an average value of how much the existing renewable wind power would contribute over the course of a year and factor that into your calculation, but if you take the stress scenario that we were talking
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about before—zero—you need a bigger margin. So certainly something more towards 10% would, in my view—and I am not an expert on these things—be closer to the mark.
Lord Willis of Knaresborough: Right.
Lord Broers: He argued that in the end that would cost less than the 4%, so there would not be the penalty to pay for it.
Dr Roberts: I respect his view. I have not heard his arguments in detail, so I am afraid I cannot comment.
Lord O'Neill of Clackmannan: He also made a point about what 10% or 20% really meant, because we have had other evidence that showed that two was actually six under the old reckoning. We really need to get a clearer expression of the numbers for this.
Dr Roberts: In time. This is where, as I say, I would need to know precisely what Dieter is attributing to wind power and so forth, and to intermittency, when he talks about 15% to 20%,.
The Chairman: I think we have to be careful not to misquote him. I think I remember him saying, “Something north of 10%”—something like that.
Dr Roberts: I would go along with that.
Q164 Lord Rees of Ludlow: Going back to the distribution system, you used to be concerned about the substations around London and things like that. Are you confident that those vulnerabilities have been reduced?
Dr Roberts: Vulnerabilities of the substations around London in what sense?
Lord Rees of Ludlow: In that if they failed we would be slow to replace them. This was, I understand, one of the big concerns that people had in the past. I am just concerned generally about whether the distribution network is sufficiently robust and could be repaired sufficiently quickly.
Dr Roberts: In general terms, London has a very robust electricity network because it is all underground. I think there are some potential problems in that a number of substations are in the basement of buildings, which can cause logistical difficulties as well as economic difficulties. But, to be honest, I do not know enough in detail about the London electricity distribution business to be able to comment. You would have to ask them the question.
Q165 Baroness Sharp of Guildford: There are two issues that I would like to raise with you. In terms of mitigating the potential social and economic impacts of interruption for electricity supplies—you have talked about the potential domino effects of breakdown and so forth in the scenarios that we have just been talking about—are the public sufficiently aware of the dangers? We learnt last week about Denmark and its Energinet, which runs the system in Denmark. We do not have anything like that now; we are relying on the market to do it for us and Ofgem says that it does not have any directional capacity on this. Is sufficient attention being paid both to the supply and to the demand side measures to mitigate this? Secondly, when picking up again this distribution issue, do you think that Ofgem and the distribution companies are sufficiently aware of the dangers of a possible breakdown here?
Dr Roberts: To answer your first question, I do not think that the public at large have the faintest idea of the importance and potential vulnerability of the electricity system. They
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certainly have no sense of the amount of money that needs to be invested in it. I will go back to what I have said before: that most people believe that they pay too much for electricity anyway, but then everybody always believes that about electricity everywhere in the world; there is nothing new about that. They also believe that they are paying for 100% availability and that they should not pay any more.
On the second point, from the distribution companies’ point of view they are very well aware of the importance of maintaining the integrity of supplies. In fact, they are incentivised by Ofgem to do that both in terms of the frequency of interruptions and the duration, and there is a symmetrical system of penalty and incentive. Certainly from my experience, both Ofgem and National Grid, in their relative responsibilities at looking at the overall integrity of the system, are very aware of the importance of what they are doing and how it needs to be addressed. Certainly, the consequence of a reduction in the supply margin is something that everybody is very alert to, and they are taking the measures that they need to take to maintain security of supply without investing excessive amounts of money.
It is a balance that has to be measured, and NGC in my experience is very professional at doing that. However, it is not widely recognised in society as a whole. Again, to repeat myself, that is one of the big challenges, both for the industry and for the political control of it: how we educate the public at large that we do have to invest significant amounts of money. Forget decarbonisation, which we all want; we just have to make sure that we still have a resilient network from now to the end of, say, this century.
Baroness Sharp of Guildford: Yes, and yet then there is also a fundamental irony in the fact that if we want the public at large to save electricity we need to have a high price for it.
Dr Roberts: Indeed, and they do not like that.
Q166 Baroness Hilton of Eggardon: On a rather different issue, you were talking about the need for better management of the systems. The Institution of Engineering and Technology has suggested that there should be a systems architect to increase integration in the system. I wondered what your feeling was about that.
Dr Roberts: I can see the point. I would say that at the moment we already have Ofgem, we have National Grid, which have nationwide responsibilities. To me it is more an institutional thing. Who would this body be? To whom would they be responsible? Do they override Ofgem? Do they override National Grid? Are they purely advisory? I can see the point perhaps in principle, but the practicalities would be very difficult to work through.
Lord Dixon-Smith: If we are looking forward and being pessimistic and we get a major national outage in, for example, 20 years’ time, by which time we are all on smart meters, it seems to me that theoretically it would be possible to manage everybody’s individual supply externally. I doubt whether it would be socially acceptable, but it could be done to spread the load. If that were to happen, do you think it would be acceptable, because increasingly we shall move that way?
Dr Roberts: We shall certainly move that way. If everybody had a smart meter, technically it would be possible to switch their supply off remotely from a central point. Whether or not that would be socially acceptable would be difficult to say, as so much would depend on the circumstances. It might be socially acceptable if you could demonstrate to people that maybe—as we had in 1974, although it was not done in anything like the same way—being
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offered three hours a day was better than having nothing at all and that was how you managed the system. If you could achieve that acceptance, then technically it would be possible. But—and it is a huge but—given that in 1974 people were not that reliant on electricity anyway, whereas 20 years from now we will be absolutely and totally reliant on electricity, the likelihood of it being socially acceptable is very remote, frankly.
The Chairman: Dr Roberts, we have detained you for rather longer than we had intended or probably you had intended. Thank you very much indeed for a very helpful session. You have given us a lot to think about, and, indeed, one or two very concrete suggestions, which I am sure that we will follow up. Indeed, we have an opportunity for further questions with Ofgem and the Secretary of State, and some of your evidence will help to inform some of their discussion, I am sure. When we started I said that we would be concentrating on your second report. In practice we have covered both reports and very fully. Thank you very much for a very full session.
Dr Roberts: Thank you, it was my pleasure.
The Royal Astronomical Society – Written evidence (REI0048)
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The Royal Astronomical Society – Written evidence (REI0048) Declaration of interests
1. Two of the authors of this submission are professionally employed in a university and in a research laboratory to carry out research into space weather and how it interacts with the Earth and its surroundings. The Royal Astronomical Society itself however has no financial interest in this area.
Written evidence
2. The Royal Astronomical Society (RAS) has around 3800 members (Fellows) and is the
leading UK advocate for the fields of astronomy, space science and geophysics. Our membership includes professional scientists working in academia and industry as well as many people with occupations across diverse sectors of the economy who use the skills and knowledge obtained during their time in academic research.
3. In 2010 the House of Commons Science and Technology Select Committee considered the issue of space weather as part of its inquiry into scientific advice and evidence in emergencies, including its effects on electrical infrastructure184. The RAS submission to that investigation considered the risks posed by adverse space weather to not only electrical power supplies, but also satellite and space-based systems essential for areas such as navigation and communications.
4. Our recommendations at that time included a better coordination of space weather research activities; efforts to raise awareness of the issue with government bodies and potentially affected private industry, and an increased financial commitment to the European Space Agency Space Situational Awareness programme.
5. This new submission concentrates on the points of interest to the Lords inquiry i.e. the impact on electricity supply systems, acknowledges progress on the points raised in the previous paragraph and notes the need to improve our understanding of space weather through new ground- and space-based facilities.
6. In recent years the risks to electrical infrastructure posed by space weather (or solar storms) have become a topic of major interest around the world. It was formally recognised as a significant risk to the UK by the incorporation of severe space weather in our National Risk Register in 2012.
7. When large eruptions of material from the Sun (coronal mass ejections) pass over the Earth they can generate severe geomagnetic storms that inject quasi-DC electric currents (geomagnetically induced currents) into power grids and disrupt the
184 See http://www.publications.parliament.uk/pa/cm201011/cmselect/cmsctech/498/498.pdf and http://www.ras.org.uk/images/stories/ras_pdfs/S_and_T_-_Scientific_evidence_and_advice_in_emergencies.pdf
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operation of key grid components such as transformers. This disruption can cause parts of the grid to shutdown leading to widespread loss of power for many hours and, in worst cases, damage to a few transformers, which could lead to long power outages in affected areas.
8. The UK has been taking an international lead role in these efforts to understand and
mitigate this risk. In particular National Grid has been working since the 1990s to improve its resilience against space weather, e.g. through use of more resilient transformers. National Grid also has specific, well-exercised, procedures for operational measures that can provide additional short-term resilience of electrical infrastructure in response to reliable warnings of adverse space weather. The work of National Grid has been reinforced in recent years by a wider UK effort to understand and mitigate space weather risks, encouraged by the UK Government through its National Risk Assessment process and supported by the willingness of UK experts from different fields to work together.
9. A notable example of this is the work of a team of UK engineers and scientists (including several members of the Society) to produce the report “Extreme space weather: impacts on engineered systems and infrastructure” published in February 2013 under the auspices of the UK Royal Academy of Engineering185. This report is now a cornerstone of UK work on space weather risks, providing much technical detail on the science and engineering of these risks, on how we can mitigate them and on what needs to be done. The recommendations of this report are now being followed up across a number of sectors including electrical infrastructure.
10. A recent example of this follow up is the formal opening of the Met Office Space
Weather Operations Centre by Greg Clark, the Science Minister, on 8 October. The Met Office building is a UK-centric service, based on international collaboration, but delivering services customised to UK needs with National Grid as a key user. The Met Office has strongly engaged with the UK scientific community so that their service builds on the existing skills base in UK universities, Research Council institutes and industry and thus can exploit innovative new science coming out of UK research.
11. These UK skills span the whole range of space weather from the Sun to the Earth, our understanding of how space weather originates in the Sun, how it propagates to the Earth and how the terrestrial environment processes energy from the Sun to produce adverse impacts in different regions of the Earth, e.g. whether a particular space weather event impact the electrical infrastructure in China, Europe or North America. These are all ongoing research areas in which work is beginning to be funded by the UK Research Councils in particular the Natural Environment Research Council (NERC) and the Science and Technology Facilities Council (STFC). There is considerable scope for further research to improve the quality of space weather forecasts used by National Grid.
12. The delivery of these space weather forecasts relies on access to data on current space weather conditions: the monitoring of activity on the Sun, the tracking of solar ejecta
185 See http://www.raeng.org.uk/publications/reports/space-weather-full-report
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heading towards Earth and the existing conditions at Earth (where prior conditions can play a major role in determining what happens when a coronal mass ejection arrives at Earth).
13. Many of our present observing capabilities are old and at risk of failure (as happened on 1 October when NASA lost contact with its STEREO-B spacecraft; this may be recovered but perhaps not for many months). Thus there is international interest in establishing new capabilities, especially through the launch of satellites and ground-based instruments, dedicated to operational space weather monitoring. The UK is playing an active role in international discussions, e.g. through our recent membership of ESA’s Space Situational Awareness programme and through contacts with developments in the US and China.
14. Scientists from UK universities, Research Council institutes and the Met Office, as well as experts from the UK space industry, are actively working with the UK Space Agency to progress these ideas. For example, a recent industry-academic study has developed a concept (named Carrington after the 19th century British astronomer Richard Carrington186) for a UK-led operational mission to monitor solar ejecta travelling towards Earth. This is now being discussed and reviewed by the wider community.
15. The strong solar activity in the last days of October 2014 has provided a spectacular demonstration of the need for better application of our understanding of space weather science. A series of strong solar flares occurred over many days but did not produce any significant solar ejecta and, as of the time of writing, no serious adverse impacts have been reported. From a scientific viewpoint it has provided a textbook example of our understanding that it is the solar ejecta that produce the main adverse impacts. But this understanding is still poorly embedded in operational and policy activities related to space weather. Thus action is needed to embed this understanding in those more practical activities, and these recent events provide an excellent basis for such action.
16. Alongside the efforts of scientists and engineers, STFC recently commissioned a public dialogue project 187on the mitigation of space weather, with a Steering Group whose members included representatives of NERC, the Met Office, the UK Space Agency, the RAS and the Cabinet Office as well as the authors of this submission.
17. The dialogue process included discussions with members of the public in a number of UK locations and was designed for example to test whether people would respond to a space weather emergency, including a major power outage, differently in rural and urban areas. Participants were also asked to assess how government, local
186 Carrington was a leading member of the Society, serving as RAS Secretary from 1857 to 1862. On 1 September 1859 he observed a large solar flare (the first ever such observation) which was followed some 17 hours later by the largest space weather event on record. This event is now often referred to as “the Carrington event” to recognise the importance of his observations. These were published in the RAS’s scientific journal, Monthly Notices, and are still frequently cited today. See e.g. http://articles.adsabs.harvard.edu/full/1859MNRAS..20...13C 187 See http://talkspaceweather.com
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communities and private industry should respond to such an event and what steps should be taken to prevent and mitigate its impact.
18. Although the final report on this project is not yet available, Committee members should note that participants became particularly engaged with and spent time understanding this issue. The participants strongly support the need for more scientific research into space weather and for the development of space- and ground-based systems to better understand how it affects the terrestrial environment. Interestingly the public were also specifically clear that they themselves had a duty to be resilient in the difficult circumstances of a severe space weather event and made links to wider resilience to other extreme weather events.
19. Outside of medicine, there are few examples of scientific research where the case being made by scientists is so clearly endorsed by the wider public. The Society therefore asks the Government to note this support and to ensure that research into space weather receives the investment it needs.
5 November 2014
RSA Group – Written evidence (REI0028)
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RSA Group – Written evidence (REI0028) 1. Overview 1.1 RSA Insurance Group welcomes the Committee’s inquiry into the resilience of electricity infrastructure. We understand the focus of the inquiry is largely concerned with the role of science and technological innovations in helping to ensure a robust framework for electricity supply. However, given RSA’s experience as a global insurer, we have used this submission to demonstrate how effective risk management can also help to improve infrastructure resilience. 1.2 This response sets out how effective risk management can help to minimise the risk of electricity infrastructure failure, as well as enable investment in technological innovations which improve resilience in the long term. In particular, we explain the importance of involving insurers early on in the design phase of energy projects, including of transmission and distribution systems, to help minimise the risk of infrastructure failure. 1.3 We conclude that risk management should not be overlooked in ongoing policy discussions about ways to secure grid resilience in the UK. 2. Effective risk management in transmission and distribution systems 2.1 RSA provides business interruption cover in the event that an energy development suffers a failure and is unable to operate. As an example, RSA estimates that 80% of insurance claims for offshore wind projects are related to transmission issues through sub-sea cable failures. If a cable fails, an entire wind park can be unable to operate as there is no way to transmit the electricity generated to shore, resulting in significant losses for the operator and impacting on the UK’s energy supply. Effective risk management of electricity transmission and distribution systems is therefore vital to ensure more resilient infrastructure. 2.2 RSA takes a proactive role in helping projects to prevent such transmission failures through effective risk management. The involvement of RSA’s risk engineers early on in the development stages can help to minimise risks and prevent faults later on in the operational phase. RSA deploys specialist risk engineers (including marine warranty surveyors for offshore projects) to assess a project during the design and construction phases. As part of the assessment, the surveyors identify potential problems that could lead to a claim in future and recommend measures to prevent the likelihood of failures occurring. 2.3 For example, in 2014 following an inspection by a surveyor, RSA made a number of recommendations to improve fire protection at a high-voltage, direct current (HVDC) convertor substation. Fire is a critical risk factor for most transmission assets, so such advice is critical to improving infrastructure resilience. To reduce the risk of fire, we recommended the substation install a gaseous fire protection system in critical electrical rooms. Other recommendations focused on improving fire protocols such as ensuring combustibles are covered with fire blankets in certain areas, and that the local fire service conduct a Pre-Fire
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Planning exercise at the substation. 2.4 RSA also encourages projects to put in place best practice contingency plans should a cable or other transmission system fail, such as having suppliers ready to provide critical spare parts as required. This also ensures a project can get up and running again as quickly as possible, supporting infrastructure resilience. 2.5 By helping to ensure the effective deployment of electricity infrastructure, good risk management also helps to encourage investment in new and emerging technologies. RSA’s expertise in risk management for large-scale energy projects has enabled us to insure a number of new infrastructure technologies that other insurers may be less willing to cover, such as the Western Link project which uses HVDC transmission. 3. Supergrids
3.1 Supergrids play a key role in improving electricity infrastructure resilience over the long term. They help to ‘de-risk’ the energy supply by spreading out the risk of infrastructure failure across a number of countries. 3.2 Supergrids provide a larger grid and greater number of interconnectors for electricity to be transmitted through, reducing the impact of individual interconnector failures on the overall energy supply, thereby improving grid resilience and securing supply. Currently, the UK gets only around three per cent of its electricity through interconnectors – this is in comparison to Germany which sources almost five times as much of its energy through interconnectors. An increased number of interconnectors will enable electricity to be diverted across borders to countries where there is highest demand, helping to ensure the UK can meet its energy needs during peak periods. 3.3 RSA has a long track record of insuring the laying and maintenance of the cables required for interconnectors. However, further investment is needed in the UK national grid to ensure it is robust enough to transmit and receive power through a supergrid as and when required. 3.4 RSA supports the European Commission’s proposals for a European supergrid and its plans to increase electricity interconnections between member states. We would like to see the UK Government play a greater role in driving forward these discussions at the EU level to ensure these plans can be delivered as quickly as possible. 4. Conclusions and Recommendations 4.1 In summary, effective risk management helps support grid resilience by minimising the risk of failure to electricity transmission and distribution systems. Effective risk management also helps to support a secure business environment for investment in new and emerging technologies, supporting infrastructure resilience in the long term. 4.2 RSA recommends that the Government:
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encourages developers to engage early with insurers in the development of project transmission and distribution systems, in order to help reduce the risk of failure during operations;
ensures risk is one of the key factors considered when assessing ways to secure grid resilience in the UK, including involving insurers and risk engineers in any policy dialogue; and
takes the lead in supporting plans to increase electricity interconnections with other countries, including the creation of a European supergrid.
5. Background to RSA 5.1 RSA is a multinational insurance group writing business across 140 countries worldwide and a market leader in the provision of insurance to energy projects, including transmission cover. RSA has around 200 dedicated Construction and Engineering experts in 30 offices around the world. 5.2 They provide specialist insurance and risk management services across construction, facilities management, engineering design and manufacturing through our extensive range of insurance products including cover for property, machinery and tools, legal liability as well as employees’ liability. 5.3 Within the Renewable Energy sector, RSA provides insurance across the full lifecycle from start up to construction and then operational cover once the facility is up and running. We provide insurance covers for the breadth of Renewable Energy technologies including wind energy (onshore and offshore), solar energy, small hydro, bio energy and wave & tidal. 19 September 2014
The Scientific Alliance – Written evidence (REI0046)
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The Scientific Alliance – Written evidence (REI0046) Cambridge and Edinburgh Authors: Sir Donald Miller FREng , FRSE, Chairman Scottish Power 1982-92; Colin Gibson FIEE, Formerly Power Network Director, National Grid; Professor Michael Laughton FREng, Emeritus Professor of Electrical Engineering, University of London. INTRODUCTION The severity of the problems facing electricity supply in the coming years cannot be examined without reference to the pattern of electricity demand as well as the quantities and types of the different types of generating plant connected to the system. Therefore we consider it important to first assess the probable characteristics of the system in the relevant years. Government targets for reducing CO2 emissions from the electricity system require that some 35% of electrical energy be generated from renewable sources by the year 2020. Some of this will be from other renewable sources, but the majority will be from wind. However, there is a strong possibility that these targets will not be achieved in their entirety and we think it will be helpful to examine the Committee's questions against the background of the most likely out-turns. National Grid, in their studies of future energy scenarios, examine four different balances and compositions of load and generation, dependent on factors such as economic growth, progress with renewables and energy savings as well as the adoption of new types of load such as electric cars, heat pumps etc. However, they do not ascribe probabilities to any of these scenarios so we have taken the simple average of the four to arrive at a scenario for the purpose of this submission. For comparison also shown in the table (see Appendix) are the comparable figures if Government targets for 2020 were fully met as also are the figures for year 2015/16 in view of the expected critical risk to electricity supplies in that year. The government target for installed wind capacity in 2020 is around 30GW. COMMENTS ON EXISTING AND EMERGING TECHNOLOGIES (PARAGRAPH 9 OF CALL FOR EVIDENCE)
1. Electricity Storage - The benefits of an efficient and economic system of electricity storage, especially one that could be sited near to load centres, has long been recognized, especially for meeting peak demands in densely built up urban areas such as Downtown Manhattan. Trials have been made using storage batteries for this purpose but these have not so far proved economic, and in any case are unlikely to be adopted on a wide enough scale to have a significant effect on the electricity system as a whole. Compressed air storage has also been considered and would be capable of storing significant quantities of energy but, for reasons of fundamental
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thermodynamics, the efficiency of this will always be low, probably less than 50%, making its widespread application extremely unlikely. Pumped storage, using reversible pump/turbines first pioneered at Cruachan, has proved attractive and, at approaching 80%, is reasonably efficient, but because of the demanding site requirements (high head and suitable locations for large upper and lower reservoirs) cannot be expected to make more than a limited contribution.
2. Interconnection with Overseas Networks - While interconnection to neighbouring
networks may sometimes allow the import of power in emergency conditions, it would seem unwise to place any reliance on this to meet system maximum demands, unless it were backed by firm contracts with consequential loss provisions. While this is we understand the case for mainland UK exports to Northern Ireland, this is for relatively small quantities of power and was agreed by Scottish Power when it had surplus output. It is difficult to envisage circumstances when an overseas generator other than a hydro utility or one with unique access to sources of cheap energy would construct plant for this purpose. In the light of this we would see Norway and possibly Iceland as the only possible sources, although the costs of transmission and the reliability of supply would be significant factors.
3. While it is sometimes claimed by proponents of renewable generation that
widespread interconnection of electricity systems across Europe will effectively guarantee firm output from intermittent sources of generation, this is not supported by detailed analysis. In fact, as a forthcoming paper by Dr Capell Aris shows, the frequency of large anticyclonic weather systems covering the whole of Europe are such that low wind outputs in the UK are frequently coincident with similar low outputs throughout Europe, so that even large scale interconnection would make a minimal contribution to security of supply. We note that National Grid in their Ten Year Statement do not take credit for continental interconnections for meeting system maximum demand.
4. Management of Demand - The costs to commercial and industrial firms of an
interruption of supply and the consequent cessation of their activities is with few exceptions far in excess of any savings made from the lower prices for an interruptible supply. The exceptions to this are generally heavy user process plants such as some chemical plants with moderate labour costs and the ability to store their product, but we would expect that nearly all of these which can accommodate an interruptible supply already do so. In the domestic market dual-rate tariffs to encourage consumers to move load to off-peak times (storage heaters, washing machines etc) were widely used, but with electric storage heating now in decline and with noise transmission in modern housing these are not expected to result in a significant degree of demand management, as a result of the wider deployment of smart meters.
5. There remains the possibility that developments in types of electrical load, such as
charging for electric cars or widespread adoption of heat pumps for heating, would be more amenable to management of demand. However we would expect that if electric cars become a significant load, the supply companies would introduce
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appropriate tariffs making it more economic to recharge them during night-time or low load periods and we would be surprised if National Grid have not already taken that into account in their scenarios. Equally with escalating electricity costs and the continued availability of reasonably priced gas it is difficult to see a major shift in heating systems from gas to electric heat pumps – added to which there is the fundamental limitation of heat pumps to supply heat at economic costs at the higher temperatures required for existing radiator systems. We would expect that heat pumps will find a market in new build using low temperature under floor heating systems rather than in conversion of existing properties, where the absence of heat storage in the structure would mean that heat pumps could not be switched off at times of maximum demands.
6. More Flexible Nuclear Technology - Nuclear generation in the UK has traditionally
been used only for base load provision. However, this is not because of any inherent limitation of the technology, but more an optimisation of the costs of generation. In France, the high proportion of nuclear generation on their grid system has required a flexible response to demand changes in order to contribute to system stability. Nevertheless some existing nuclear plants in the UK can provide some flexibility, being able to reduce load by a limited amount over a prescribed period. Five out of eight UK stations already offer this for grid system faults during grid outages and one can also provide automatic frequency response as a contribution to grid stability.
7. Developments in new nuclear reactors will include greater flexibility to respond to
demand changes and to contribute to grid system stability, although it should be recognised that because of the low marginal cost of nuclear this will be a costly exercise compared with using fossil fuel generators in this role and is likely to be a last resort in the face of increasing penetration of wind and solar generation. The flexibility and grid stability contribution from nuclear generators will depend to some extent on design choice but there is no reason to limit the amount of new nuclear generation on this account.
8. Carbon Capture - This is still an unproven technology: severe doubts exist whether it
will make a significant contribution to the system as whole, not least because of the high costs and reduction in efficiency of the generating plant (of the order of 25%). Because of the escalating costs of electricity to the consumer and the implications of high energy costs for the economy it will become increasingly important to concentrate on technologies which have good prospects of delivering supplies at lowest possible costs. For these reasons it would seem unwise at this stage to place any great reliance on this technology making a significant contribution.
9. Flexible Hydro Generation - Conventional Hydro is certainly able to respond to
system demands in times varying from a minute or so to several minutes. However the total capacity of hydro generation connected to the grid system is some 1400 MW and the available potential is virtually all already developed. There remains perhaps some 200 MW in very small run of river installations (or with limited storage) and which would be connected to the distribution networks. These are presently being developed because of the attractions of the ROC system of subsidies, but at
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significant cost to the consumer. Because of the lack of seasonal water storage, only a small proportion of these can be expected to make a reliable contribution to meeting peak demands.
10. Increasing the Diversity of the Renewables Portfolio - We are not aware of possible
renewable sources which meet the twin objectives of affordability and reliability. It is sometimes suggested that the widespread adoption of marine energy (tidal flows and wave) would reduce the problems of intermittency from wind power but this effect, if it exists at all, is not seen as significant. It should be remembered that wave energy is also a function of wind and that, as winds fall, low wave energy follows with only a small time delay. Tidal flows, while largely independent of wind, experience four periods of low output per day even at springs and will generally have rather low outputs at neaps with generation unrelated to times of maximum demand. Therefore, far from ameliorating the problems of intermittency, they will add to them.
11. As we shall show later in this submission the most severe problems in the resilience
or reliability of the electricity supply system stem from the large amounts of intermittent and non despatchable renewables already being connected to the system under the ROC and Capacity Credit regimes.
SHORT TERM (to 2020)
12. Under the Electricity Acts the supply authorities (CEGB, SSEB and the Hydroboard) had an obligation to supply, and to meet this obligation provided a generating capacity margin above winter MD of some 20-24% with a higher figure for seven years ahead of 28%. This was equivalent to a loss of load probability of four winters in 100 years. In order to fulfil this obligation at the lowest practicable costs to the consumer, the Boards carried out regular ‘whole system cost’ studies of a wide range of strategies to determine the most attractive option.
13. At privatization, the responsibility for providing adequate supplies was left to the
market with neither the generators nor Ofgem being required to take positive action to meet any shortcomings. National Grid’s responsibility is limited to making the best use of plant offered to it to meet demands. Likewise the use of whole system cost studies was abandoned, with DECC, amongst others, resorting to quoting the less meaningful ‘discounted energy costs’ for specific types of generating plant. This approach ignored the well-known interaction of different types of generating plant on an integrated electricity supply system and failed to distinguish between the requirements and costs of meeting system maximum demands as distinct from energy requirements.
14. Later, in the year 2000, the NETA trading arrangements were introduced in an
attempt to prevent generators gaming the market by manipulating the availability of generating capacity and receiving high payments from the Pool for offered capacity. NETA allowed generators to supply their contracted loads directly instead of selling into a national pool. The appropriate pattern of demand for domestic and
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commercial consumers was not metered but was based on assumed shapes of load curves for the average consumer. More recently, under the Electricity Reform Act, DECC have assumed some responsibility for meeting future system maximum demands and costs to consumers by the introduction of Capacity Auctions for different types of new generating plant. The basis on which these auctions are decided is not clear, as DECC have made no mention of whole system studies or costs to consumers.
15. We hope that this potted history of relevant factors in the UK electricity Supply
System over recent years will be helpful and assist in putting our answers below to the Committee’s specific questions in a more meaningful context.
16. Ofgem has recently made the point that the plant margin for winter 2015/16 is at an
all-time low of some 2% after using reliefs of load management. Expressed in these terms this may not sound too alarming but in practical effect it could mean that load shedding would be required for two hours over the periods of peak demand for more than a month for several years in succession before the situation can be remedied. This is far below the standard to which we have been accustomed and it would be surprising if it did not have political implications. It has been reported that National Grid are taking emergency measures to increase these margins by contracting with owners of small private standby generators for emergency supplies. It is not known to what extent this will be helpful, but the costs per KWhr are likely to be high.
17. As the figures in the Appendix show, based on an average of the National Grid’s four
scenarios, the supply position in 2020, at only 18% margin as compared with a target of 28%, is still likely to be critical. This is largely a consequence of the withdrawal of some 8 GW of conventional generating capacity between 2013 and 2015, which is not compensated in terms of firm capacity by the increase in renewables, principally wind. Another way of looking at this situation using probability theory results in a requirement for an additional 15,500 MW of gas turbine capacity to be commissioned by 2020 to achieve a risk level of 8% (as in the 2013/14 winter), equivalent to a failure of supply in eight years in one hundred. It should be remembered that these margins are against the background of no growth in demand and, even so, are likely to result in extended periods of loss of supply over periods of high winter demand.
18. In view of the short time scale it seems unlikely that significant capacity of new
conventional generation could be constructed and commissioned in time to improve the supply position by 2020 so that the most effective course would be to defer the withdrawal of some existing capacity, as presently planned. Further measures would be to encourage the installation of some open cycle gas turbine generating capacity and increase, where practicable, incentives for more widespread load management for consumers with large commercial and industrial loads. Both of these measures are likely to prove costly for the consumer.
19. We have thought it would be useful to the Committee if we also assessed the costs of
the present policy concentrating on renewables with those of an equivalent
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investment programme with conventional generation. In both programmes we have kept the nuclear and conventional capacities the same as in the average of the four National Grid FES scenarios and in order to make the programmes comparable, have varied the amounts of new gas turbine capacity installed to achieve an 8% risk. This means the renewables programme would require an additional 15,500 MW of gas turbine generation above the average FES figures as against 19,300MW for the conventional alternative. We estimate the additional cost in 2020 with the renewable programme would amount to some £12.3 billion, equivalent to £165 or 25% on the average domestic consumer’s bill. Commercial and industrial consumers each face similar costs, but in their case augmented by the higher VAT rate, and these too will eventually fall to the domestic householder in the higher costs of goods and services. To all these have to be added the costs of carbon taxes which, based on the prices in the 2014 budget, would add a further £50 to the average domestic consumer’s bill by 2020. Adding these various elements of the energy programme results in the astonishing increase of some 90% by 2020, expressed as a proportion of the average household electricity bill.
20. There is no effective means of evaluating the costs and benefits of alternative
investment and planning strategies other than carrying out ‘whole system cost’ studies. If DECC are now to assume responsibility for deciding planning strategy in the electricity industry (as would seem to be the case under the Capacity Auction Scheme) we consider it vital that such studies should be carried out as a matter of urgency and the results made generally available. It is our understanding that Government’s intention is to invite tenders for new plant without first carrying out such studies. If so they can have really no idea of the different types and quantities of generating plant required in the consumers’ interest and this in our view would be a clear dereliction of their responsibilities.
21. We believe that the next few years could be crucial in bringing home to Government
the limitations of present policies, entailing as they do an over-concentration on renewable and intermittent sources of generation. To date there has been little or no recognition of the fact that electricity is of value only if it is available as and when required and that generation at other times has no value and is in fact an embarrassment. In short, the concentration on energy and the failure of the various market mechanisms to recognize the equal importance of capacity (the ability to meet demand at all times) results from lack of appreciation of the implications of the fact that unlike other commodities, electricity cannot be stored, or at least not in quantities sufficient to allow normal market mechanisms to apply. It is because of this failure that DECC, under their ‘Electricity Reform Proposals’ have decided to enter the market by inviting proposals for new generating capacity. Whether or not this will prove effective in attracting bids to provide the required types and quantities of new generating capacity is too early to say, but it clearly represents an unprecedented executive role for Government (even compared with that of the nationalised industry) rather than the regulatory function which is usually seen as appropriate in relation to private industry.
22. Whether or not Government is equipped to fulfil this role, there must be concern
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that, when inviting bids for new plant, they appear to be in a weak negotiating position. This became apparent in the contract negotiations for new nuclear capacity at Hinckley. While the price agreed was similar to the published expected out-turn cost for the first plant being built at Flamanville in France, we would have expected a significant reduction for a second plant of virtually the same design provided from essentially the same supply chain. Certainly these costs are high compared with those published by the USA Energy Administration for equivalent nuclear capacity now under construction there.
23. In particular the next few years should provide firmer information in areas such as:-
i. The high costs to consumers of present policies concentrating on renewables. This is a consequence of the ROC subsidies, the high costs of transmitting wind output from remote locations to the load centres in the SE, as well as the costs of running back-up plant at lower efficiencies at part load.
ii. The effectiveness of present policies in terms of reducing CO2 emissions. Studies
of actual system performance for the Republic of Ireland and in the Western US indicate that the savings in CO2 emissions for the system as a whole are significantly less than would be assumed from a simple substitution of wind for thermal energy, principally due to the less efficient performance of back up thermal generation which has to be run at part load. In fact these studies indicate that, with coal plant as back up, there are no savings, and CO2 emissions can even be increased in some circumstances. No detailed information has been made available of UK system operations to allow a proper assessment of this.
iii. The extent to which renewable generation will need to be constrained off the
system with high compensatory payments which will be charged to consumers bills. Taking the Appendix for year 2020 there would be some 21,239 MW of wind as well as 6,600 MW of solar installed. National Grid estimate this will require some 7,000 MW of short term response to compensate for rapid variations in renewables output in addition to the 5,000 MW required for system regulation and sudden loss of the largest infeed. Because of the need to run fossil fuelled plant at part load to provide this response, there will simply be insufficient demand to absorb the wind output even at moderate wind levels, so necessitating that wind output will need to be constrained off the system and requiring high compensatory payments to the generators. National Grid has estimated that it will be necessary to constrain off wind generators in some 40 days by 2020. In fact because of the need to run back up generating plant and the implications of constraining off wind, the Government’s target of meeting 35% of electricity requirements from renewables would seem to be a practical impossibility.
iv. The ability of the system to maintain its integrity following an electrical fault is a
function of the inertia of the generating plant. For this purpose it is usual practice to increase the inertia of generators, such as hydro, which are remote from the load centres. However wind generators, being non-synchronous, do not add
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inertia to the system and are therefore more likely to lead to loss of supply following a fault. We think it probable that this was a contributory factor in the widespread and extended loss of supply in the Highland Region earlier this year. Furthermore AC systems naturally increase the forces holding the system together following a fault whereas DC connections, which are increasingly being employed to transport wind power from the North of Scotland to load centres in the south of England, have no such ability. These factors will set a limit to the amounts of conventional generation which can be displaced at any time by intermittent generation if serious degradation in the reliability of supply is to be avoided.
v. As the preferred option of additional nuclear capacity will be insufficient to meet
requirements until later in the 2020’s, it will be necessary to meet the shortfall in thermal generating capacity by concentrating on CCGTs, possibly with the addition of some OCGTs. While the availability of piped gas supplies is likely to be augmented with imports of liquefied gas, its distribution to new generating stations will make heavy demands on the gas network. This will need to be assessed and planned accordingly.
MEDIUM TERM (to 2030)
24. The resilience and reliability of the electricity system will be placed under ever greater strain with the installation of large amounts of intermittent generating capacity – some three times the present capacity by 2030 in the median scenario in the Appendix. We estimate the additional costs of meeting the demand of this scenario compared with a mix of new nuclear and CCGTs would be some £26bn pa, equivalent to a 53% increase in the average domestic consumer’s bill. This is before adding the costs to commerce and industry (which eventually fall to the householder), or the costs of carbon taxes.
25. If present policies are continued we see no escape from the increasingly severe and
costly implications for operating the system together with a reduction in reliability of supplies even more severe than is now being reported from Germany because of the very large installed capacity of intermittent generators there. We see no relief from this in terms of local generation; the economies of scale are nowhere greater than in electricity supply and it was to achieve these that the CEB was introduced in the 1920’s, to secure the benefits of an integrated system with large central power stations. In fact, because of the 1939-45 war, it was not until the late 1960’s that the UK was able to substitute large central stations producing at low costs for the uneconomic smaller municipality- built electricity stations.
26. Our comments on modelling, or rather the lack of it in relation to whole system
studies under the present market arrangements, are set out in the preceding section. This constitutes a serious weakness which should be addressed as a matter of urgency.
27. We argue that present policies cannot deliver the three objectives of reliability,
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decarbonisation and affordability. Already the number of households in fuel poverty is not acceptable in a modern advanced society. The appropriate policies cannot be developed simply as a result of political debate; there is an overwhelming case for more comprehensive engineering-led studies on how to achieve the best balance between these conflicting objectives. It is only once this information is available that there can be a meaningful political debate to decide what is acceptable and practicable and to what extent the objectives need to be modified.
28. It seems likely that the outcome of such studies would be a greater emphasis on new
nuclear (to the extent that it is practicable in this relatively short time scale) augmented by CCGTs, with some reduction in the emphasis on renewables. The most effective ‘game changer’ in this timescale is likely to be a thoroughly worked out and engineering-led nuclear strategy– for example just how many different types of nuclear reactors should the UK be considering in what is a relatively small economy, and should we be taking steps to re-establish a home-grown nuclear capability which was lost under an earlier Government when it sold off the then British-owned Westinghouse Nuclear to Japan.
29. At the present time UK industry is not in a position to take a lead in these
developments and it would need far-sighted and determined Government intervention to re-establish a UK industry. In this context, it should be appreciated that nuclear, as the most economic and secure source of electrical energy, is expected to be increasingly important as fossil fuels become more costly and subject to political uncertainty. While UK governments seem prepared to spend large sums on blue sky science such as nuclear fusion, they seem unaware of other possibilities which are much closer to commercial application and which would truly be game-changing. One such promising development would be the development of the thorium-fuelled nuclear reactor and possibly also the thermodynamic cycle using CO2 instead of steam.
30. The present structure of, and modus operandi of, the electricity industry in the UK is
unique in world terms, and the number of major changes which have been introduced since privatization in the 1990’s (and which are still continuing with the recent Electricity Reform Act) confirm that it has not been without its problems. The more usual pattern is for the electricity generators to be charged with total responsibility for supply in a defined area, with investment and tariffs subject to regulatory approval. Such a structure is quite compatible with competition to supply large industrial or commercial loads outside the concession area. In such a structure, responsibility is clearly defined, with no requirement for outside executive involvement. Nor is there any indication that this leads to a less satisfactory outcome for the consumer; indeed it was the pattern under which the two Scottish generators operated for the first two years under privatisation. There would clearly be difficulties for Government in introducing such a major restructuring at this stage, but it seems likely that something of this sort could yet prove more satisfactory than the present system with its high costs and periodic major overhauls in an attempt to address the continuing difficulties as they emerge. In our view, the Electricity Reform Act, with its confusion of responsibilities and its weakening of financial disciplines, is
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unlikely to be successful in achieving satisfactory outcomes for the consumer. Acknowledgements:- The Authors are grateful for the contributions from Keith Burns FIMechE on the subject of nuclear flexibility and helpful comments from colleagues on the drafting of this submission. 30 September 2014
APPENDIX
Installed capacity [MW]
De-rating Factors
De-rated Values [MW]
2015/16 2020/21 2030/31 2015/16 2020/21 2030/31
Nuclear 8,981 8,981 8,189 1.000 8,981 8,981 8,189
Coal 16,238 8,667 1,691 1.000 16,238 8,667 1,691
Gas 29,320 34,117 34,526 1.000 29,320 34,117 34,526
CHP 4,198 4,880 5,282 1.000 4,198 4,880 5,282
CCS 0 0 4,063 1.000 0 0 4,063
Interconnectors 4,000 5,500 8,650 0.000 0 0 0
Onshore Wind 7,903 12,537 16,185 0.096 759 1,204 1,554
Offshore Wind 5,041 8,703 21,378 0.096 484 835 2,052
Solar 4,129 6,624 12,630 0.050 206 331 632
Biomass 2,124 3,193 3,420 0.700 1,487 2,235 2,394
Hydro 1,672 1,857 2,452 1.000 1,672 1,857 2,452
Other Renewables 1,349 1,559 2,832 0.050 67 78 142
Other 3,572 3,499 4,095 0.700 2,500 2,449 2,867
Generation Equivalent thermal installed
88,529 100,115 125,392 65,913 65,635 65,843
ACS Peak Demand 60,741 60,091 60,335 0.925 56,185 55,584 55,810
Conventional Gen. 62,309 60,143 57,845
Renewable Gen. 22,219 34,472 58,897 Plant Margin %
17 18 18
Demand Side Management
1,500 2,700 2,525 Standard 24 28 28
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Hugh Sharman – Written evidence (REI0006) The balancing capacity issue A ticking time-bomb under the UK’s Energiewende 1. Thumbnail summary The UK Government’s ambitious renewable electricity targets are likely to be met. Unfortunately, the effort and financial subsidies that have done so much to cause huge quantities of wind power to be built has not been matched by the serious effort nor finance needed to deliver commensurate quantities of balancing power to keep the electricity system stable and the “lights on” for when the wind does not blow. The 30 GW of combined cycle gas turbines (CCGTs) that were listed by DECC as operational as of May 2013188, even generating plant that was delivered as recently as 2010, are proving unequal to the task of balancing wind power because this task requires greater flexibility, faster start-up and stopping times and relative robustness to frequent starts and stops. These attributes are physically beyond their capability. The case of Ireland, where wind penetration reached 18% in 2013 and where CCGTs also deliver nearly all the balancing power, demonstrates that these are performing badly, having a fleet efficiency of roughly 40%, compared with its name-plate rating of or over 55% and which in any case suffers accelerated heat rate deterioration when units are ramped up & down. This low and deteriorating fleet efficiency is accompanied by abnormally high rates of wear and tear189. The case of Irish CCGTs is a sort of “canary in the coalmine” warning of things to come in UK. The complete absence of suitable generating plant that is needed to deliver stable balancing power to the stochastically operating renewables will extend the electricity supply crisis by another decade, at the least and cost many £billions of further investment that are not presently recognised by the UK’s policy makers. During the six years remaining before 2020, the quality of supply will worsen. The fact that no proper financial provision has been made for balancing so much stochastically available electricity will also drive up the price of power to the general public. 2. UK’s renewable electricity targets for 2020 are likely to be met190 Renewable electricity generated in the UK during 2013 amounted to 52 TWh, roughly 14% of all electricity generated (and 16% of energy consumed). Of this 27 TWh, or roughly 7% was generated from wind power.191
188 DECC, DUKES Table 5.11, May 2013. 189 The heat rate of the UK fleet in recent years has been rising and the efficiency falling to well under 50% (LCV), DECC DUKES 5.10, 2013. 190 http://ref.org.uk/publications/313-progress-towards-the-2020-renewable-electricity-target. 191 https://www.gov.uk/government/publications/energy-trends-section-6-renewables.
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Whether or not one approves of the UK Government’s energy policy, in any case an inheritance of the UK Climate Change Act of 2008192 and of the EU Renewables Directive193, one thing is clear. The financial support for “low-carbon” but stochastically available generation has unleashed massive spending for this type of power. But this policy has disincentivized investment into the fossil-fired dispatchable capacity that can deliver secure supplies in cold, windless weather.
TABLE A: STATUS OF UK RENEWABLES TARGETS, SPRING 2014194
Project Status Biomass Hydro Solar Tidal Waste Wind Offshore
Wind Onshore
Total
Operational (GW) 3.0 0.4 1.1 0.0 0.5 3.7 7.3 16.1
Under Construction (GW) 0.3 0.01 0.6 - 0.5 1.4 1.5 4.3
Awaiting Construction (GW) 2.9 0.1 1.5 0.1 0.9 4.3 5.1 15.0
Total Consented Capacity (GW) 6.2 0.5 3.2 0.1 1.9 9.4 13.9 35.3
Submitted in the Planning System (GW) 0.5 0.02 1.4 0.3 0.2 9.1 6.5 17.9
Load factor 66% 36% 10% 8% 68% 34% 26% -
Est. output from consented capacity (TWh) 36.0 1.7 2.8 0.1 11.3 27.8 13.1 110.8
Est. output from capacities in planning (TWh)
2.9 0.1 1.2 0.2 0.9 26.7 14.6 46.6
Notes: a) Load factors derived from DECC, Digest of United Kingdom Energy Statistics (2013), Table 6.5, use the conservative unchanged
configuration data where possible. b) For reasons of concision, Geothermal and Wave data have been removed from the table, though their
minor contributions are recorded in the totals.
192 The vote in favour of the motion was overwhelming, quote “The House having divided: Ayes 463, Noes 3”, unquote http://www.publications.parliament.uk/pa/cm200708/cmhansrd/cm081028/debtext/81028-0021.htm. 193 Main driver of UK policy on renewables is the EU Renewables Directive of 2009, which requires that 15% of Final Energy Consumption in the UK should come from renewable sources in 2020. The UK govt. expects that that about half this quantity will come from electricity, entailing that about 30% of final electricity consumption will be renewable. 194 The assumption in the table is that renewable electricity is not constrained by bottle necks in the rest of the system.
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The foregoing table A was compiled by the Renewable Energy Foundation from UK government data held in the Renewable Energy Planning Database, together with technology load factors reported elsewhere in government data. It shows that, if all the consented capacity is built, then the Government’s “renewables” targets for 2020 will be comfortably over-achieved. According to earlier estimates, if renewable electricity is to form 30% of electricity consumed then 15% of all energy consumed in the UK in that year will be from renewable resources. It helps to view this data graphically.
Figure 1
Figure 2
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Thus by 2020, if all consented capacity in 2014 is commissioned, about which one can still retain some scepticism, there will be 53 GW of renewable capacity of which only 6 GW, mostly biomass-fired boilers, like Drax, could be said to be dispatchable in any way. Wind power will constitute 39 GW. This renewables capacity, if built, will deliver an expected 157 TWh in 2020195. This will constitute 42% of the 370 TWh of electricity that were generated in 2012196. If demand stays roughly stable until 2020, after five straight years of demand falling, 42% of electricity will be generated from renewable resources. This is far more than the target of 30% of electricity consumed required by the EU Directive and the Climate Change legislation and the inter-connected EU agreements and “commitments”. An initial reaction to this data is that the present Coalition and whoever wins the election in May 2015, can relax the apparently relentless drive to encourage the building of even more new and expensive renewable capacity because what is already listed will comfortably deliver all its targets by 2020. It may therefore be rational to expect a slow-down in the rate of new developments. Similar slow-downs in the previously frantic growth of renewable electricity are already occurring in Spain and Germany. But there is a stronger reason to re-appraise the whole programme. This is because if so much wind and PV capacity actually gets built, the rest of the electricity and especially generating infrastructure is quite unfit for balancing the stochastic generating capacity that looks like being on-line in just over five years from the date of this document which is mid-2014. The basic physics of maintaining the stability of an island grid have not changed one iota during these past years. Whatever “smart grid” enthusiasts insist that their technology “will change everything”, in the absence of storage197, generating capacity delivered into the grid must always be balanced by the demand drawn from it, from second to second. Electricity storage is still in its infancy, with a few “demonstration” plants being built at the scale of less than 10 MW. It is relatively simple to balance the UK grid, in 2014, while roughly only 10% of its generation is supplied stochastically. Demand is still pretty much predictable and as long as the system still has ample reserves of dispatchable thermal generation. The task of balancing the system will become exponentially more difficult as stochastic inputs to the system grow beyond this. This is because GB’s incumbent, fossil-fuel-fired generating capacity was never designed for performing this task. 3. How wind balancing is performed in 2014
195 Consented capacity will generate about 110 TWh. If all capacity in the planning system is also consented, this will add a further 46.6 TWh. 196 A bold assumption, given the faster faster economic growth that has been delivered recently? 197 UK has 2.8 GW/25 GWh of pumped storage which located in Wales and Scotland, with 600 MW additional pumped storage that SSE is developing at Loch Ness. This is trivial in relation to the average 1,000 GWh generated and consumed every day but of course, is useful capacity for helping to stabilize the system.
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Figure 3
The chart shows that demand for this randomly chosen but still “low-wind” month, varies roughly between 40 GW during the working day and 25 GW valley demand between midnight and about 5 AM. Nuclear power ran continuously at close to capacity198. A large part of the coal capacity is turned down or off at night, responding to lower demand (and lower prices) but is kept hot to restart the next day. Nearly all the rest of the variable demand and generation is managed by starting and stopping CCGTs or by turning these up and down. When wind output is low (figure 4), the daily pattern of operation of the CCGTs allows both the transmission system operator (the TSO is National Grid, referred to hereafter as Grid) can plan and dispatch capacity with little need for more “hot” or “spinning” reserves than is needed to keep the system stable if the largest generator in the system, Sizewell B, suddenly fails.
198 Dungeness B was unexpectedly forced to close down due to a failure half way through the month, illustrating a normal hazard to be expected in an ancient electricity system, nearing the end of its design life.
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Figure 4
The operating profile of the CCGTs involved in daily balancing changed when the wind blew harder earlier in September 2013.
Figure 5
All the CCGTs that supplied the “top” 4 - 6 GW of daytime power must be ready to ramp up and down at very short notice or are required to be frequently started and stopped. Neither oil199 nor open cycle gas turbines (OCGTs) were operated during the month indicating that, despite the difficult and expensive operating conditions for the CCGTs, it was still more “profitable” to keep the CCGTs in operation for daily balancing.
199 All the oil-fired power stations are now decommissioned.
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The operation of the grid became more stressed in the much windier month of December 2013.
Figure 6
The peak output of the CCGT fleet during the week, from Sunday the 15th thro’ 22nd December, “daylight” CCGT load was 17 GW but on a windy Wednesday was only 14 GW. The lower peaks during the latter part of the week probably reflect the proximity of the pending Christmas holiday. The daytime variation was in the range 3 – 6 GW.
Figure 7
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OCGTs delivered 0.01% of all power during the month, illustrating that no matter how uncomfortable it is for the CCGTs to operate in these conditions, they are still bidding into an energy market that makes these more attractive to operate than OCGTs. The grid-connected wind fleet in GB at the end of 2013, was roughly 8 GW200. By 2020, if (say) 40% of all power is to be generated from renewable resources and 88% of this is planned to be wind, the grid-connected wind fleet will grow from 8.4 GW (June 2014) to 39 GW, by a factor of 4.9. 4. The system in 2020 By 2020, only 5 years from now, it is most unlikely that any new inter-connectors will have been built and commissioned. Due to the combination of the Large Combustion Plant Directive (LCPD) and the Industrial Emissions Directive (IED) it is likely that dispatchable capacity will have shrunk considerably. Of 21 GW of surviving coal capacity at the end of 2013, only Ratcliffe power station in Nottinghamshire, owned by EON, is believed to be fully IED compliant beyond 2023. All IED-non-compliant generation from the beginning of 2016 must either retrofit new technology to existing plants to ensure they comply with the new pollution limits or agree to a so-called Limited Life Derogation (LLD). This means that from the start on 2016 the LLD plant can only operate for a maximum of 17,500 hours from 1st January 2016 until the end of 2023201, or an average of only 2,500 hours per year. As was the case with the LCPD, it seems highly likely that those generators with older non-compliant plant that will be expensive to upgrade, and taking into account the rising tax on CO2 emissions, will run their equipment through their 17,500 hours as fast as possible rather than upgrade these, causing a sharp reduction of dispatchable capacity towards 2020. The IED also applies to CCGTs, affected by NOx emissions as well as coal-fired units. Accordingly it is entirely reasonable to expect quite large scale closures of some older coal and CCGT capacity by 2020, spurred not least by the gradually increasing tax on CO2 emissions. If Labour wins the 2015 election, it has promised to ensure more stringent environmental restrictions on older plant than might be expected if the Conservatives form the new Government. As regards nuclear, all the Advanced Gas-cooled Reactors (AGRs) are on “life-support” beyond 2016 when most were scheduled to close. EdF, their owner, is working hard to extend their lives. Hopefully, only Dungeness B will be fully de-commissioned by 2020. However, all these plant life extensions will require extensive periods off-line so that the necessary safety-related improvements can be made.
200 “Embedded” wind power which is not monitored by Grid is roughly 2 GW. This type of the wind power is most unlikely to grow. 201 http://www.businessgreen.com/bg/news/2322241/rwe-npower-confirms-plan-to-close-uk-coal-power-plants
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Figure 8
As figure 8 illustrates, the output of the UK fleet has been highly erratic for the past few years, so it is reasonable to expect an average nuclear fleet output to be 2 GW lower than the 8 GW average achieved through most of 2014. For the purpose of taking a view on the balancing of power in 2020, I have selected to extrapolate the conditions of December 2013 to 2020. Assumptions In the following calculations, the following assumptions were made:
Demand patterns and aggregate demand remains the same as in 2013202
Inter-connections, remain as per 2013 but always export 3 GW to France and Netherlands whenever the wind exceeds 10 GW203.
No exchange between Ireland and GB during high wind conditions because wind correlation between GB and Ireland is so strong
Pumped hydro and hydro will remain as 2013204
Coal (and biomass) output will be 7,500 MW less than 2013
Wind capacity will 4 times greater than during 2013205
CCGT “will be retained” in the system at whatever level is required to meet peak annual loads
202 In Denmark and Germany, where renewable penetration is much higher than in UK, changes in the pattern of use of power intended to exploit changes in the amount of renewables produced, have been negligible. 203 Neither the new Channel Tunnel inter-connector nor the proposed Norway inter-connector are assumed to have been commissioned before 2020. 204 It is possible but improbable that the 0.6 GW pumped hydro at Loch Ness will be commissioned by 2020. 205 32 GW, a more conservative assumption than the 39 GW foreseen in REF’s paper.
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System operation in 2020
Figure 9
It is instructive to see this situation at a higher resolution for the week 15th thro’ 22nd December.
Figure 10
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On the sixth night, because of lower demand, fossil-fired generation is briefly turned off completely206 and the whole of GB is powered by wind and nuclear, despite strong exports to France and The Netherlands. CCGTs are supplying virtually all the power needed to balance between generation and demand. How wind power and CCGT output interact during this period of high wind is shown in the following charts.
Figure 11
206 For the purpose of this paper, issues of grid stability, inertia and ROCOF (rate of change of frequency) are conveniently ignored. They must be addressed of course but will not be dealt with this paper.
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Figure 12
It is abundantly clear that with this quantity of wind power in the system, even with 7,500 MW of coal closed down, and wind power taking priority for dispatch, that by 2020, no CCGTs at all will be operating in any way resembling base-load. Yet, during periods of low wind, there will have to be at least 30 GW of CCGT (or other dispatchable) capacity beyond nuclear, if only “to keep the lights on”. It is also clear that any more wind power than the 32 GW simulated in these calculations would threaten the base-load status of the diminished nuclear fleet. However, this type of operating regime, with constant starts, stops and hard ramping will rapidly destroy GB’s large, incumbent, and elderly CCGT fleet. The unsuitability of the Frame-type CCGT for multiple starts stops and hard ramping
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Figure 13
Source: Author, compiled from DECC Table DUKES 5.1 (2013)
This is because the start-up cycle of the typical, incumbent CCGT is so long relative to the average time that it will be operating at full, optimum load.
Figure 14
Source: www.Corelia.co.uk
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Synchronisation does not begin until roughly a half an hour after the start button is pressed. The Frame-type turbine does not reach full output for seventy five minutes. During the whole, 100 minute plus long, start-up operation, full load and optimum efficiency will, in many cases, last just a few hours before the 40 minute shut-down process begins, during which time, once again, the CCGT will be operating with greatly sub-optimal efficiency, causing disproportionate fuel costs and high specific emissions. Furthermore, in addition to the high fuel and emission costs, which can average £10,000 - £13,000207 in fuel and emissions, each new start is costly in wear, tear and shortened component life, estimated by a notable industry consultant as £10,000 - 12,000 per start208. Every time a power plant is turned on and off, the gas turbine, HRSG or boiler, steam lines, steam turbines, and auxiliary components go through unavoidably large thermal and pressure stresses, which cause damage and incur additional future costs. Frequent starts and stops and high ramping and up and down will shorten the periods between serious and costly outages caused by failures in the major components in the steam and gas generating equipment. This damage is made worse by fatigue and creep-fatigue interaction damage. These cycling-related costs and damages are strongly correlated to start-up, shutdown, and rapid load following. It is therefore necessary to estimate and compare them to similar combined cycle plants with longer histories, where there is more data for start/stop and load following costs, the so-called cycling costs209. In summary, these costs fall into the following main categories
Increases in maintenance, operation (excluding fixed costs), and overhaul capital expenditures
Increased time-averaged replacement energy and capacity cost due to increased equivalent forced outage rates (EFOR)
Increase in the cost of heat rate changes due to low load and variable load operation
Increase in the cost of start-up fuel, auxiliary power, chemicals, and extra manpower for start-ups
Cost of long-term heat rate increases (i.e., efficiency loss) All the UK’s CCGTs are, to a greater or lesser extent vulnerable to these issues which deteriorate as the plant’s running hours increase. 5. How they manage balancing elsewhere Denmark The case of Denmark is most instructive, as always.
207 Private communication, generation industry source. Gas priced at £7.50/GJ. 208 Private communication, generation industry source and http://www.nrel.gov/docs/fy12osti/55433.pdf 209 In Ireland, where wind penetration reached 17% by 2013, there is a wealth of closely held data about the maintenance costs of CCGTs stressed by balancing wind power.
Hugh Sharman – Written evidence (REI0006)
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Figure 15210
Denmark’s wind power generated during 2013 was 34% of all power generated in Denmark and the equivalent of 33% of power consumed in Denmark. Denmark was a net importer of power during 2013. The chart illustrates how, whenever the wind blows strongly, a high proportion of Danish wind power is not actually consumed in country but instead floods into neighbouring systems (Norway, Sweden and Germany) through inter-connectors, the aggregated capacity of which have the same capacity as Denmark’s peak load. This is 5.8 GW and will grow to more than 7 GW by 2020, if current plans are fulfilled211. Germany A similar phenomenon can be observed in Germany where stochastic renewables in 2014 constitute roughly only 15% of all electricity generated.
210 Data compiled from www.energinet.dk by the author. 211 In other words, the inter-connected capacity of the UK would have to be 60 GW to achieve the same flexibility as the Danish system.
Hugh Sharman – Written evidence (REI0006)
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Figure 16
Germany, power generation, demand and net power flows212 June 16 – 22, 2014
Most of the time, peak PV output (especially) coincides with up to 10 GW of exports that are flooding into its eight inter-connected, neighbouring systems. Indeed, Germany has been a net exporter of electricity ever since the rapid build-up of PV started in 2009. The abrupt slowdown in the rate of growth of its stochastic generating infrastructure that is taking place during 2014, is due almost as much to the objections of its neighbours, whose much smaller transmission systems are under pressure from loop-flows generated from Germany, as due to the unacceptably rising costs being imposed on German consumers by the “renewable energy law”213. The inter-connector balancing capacity that is available to Denmark and Germany, will simply not be available to the UK, by 2020, the year that (possibly, if improbably) up to 40% of the UK’s generation will come from stochastic renewables, its inter-connections with France and the Netherlands will be no more than now, 3GW and altogether, with Ireland, 4 GW214. Ireland The two foregoing cases demonstrate the central importance of having high inter-connections with neighbouring electricity systems in order to achieve high levels of
212 http://www.agora-energiewende.de/service/aktuelle-stromdaten/stromerzeugung-und-verbrauch/ 213 http://www.economist.com/news/europe/21594336-germanys-new-super-minister-energy-and-economy-has-his-work-cut-out-sunny-windy-costly 214 https://www.ofgem.gov.uk/electricity/transmission-networks/electricity-interconnectors
Hugh Sharman – Written evidence (REI0006)
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integration, in the absence of large levels of pumped hydro and/or other storage, as demonstrated in the cases of Spain and Portugal. All these cases, though interesting, are not relevant to the focus of this paper which is how the UK will raise wind penetration from 7% in 2013 to almost 40% by 2020. The Republic of Ireland (ROI) generated 18% of its electricity from wind turbines during 2013215 and its policy is to generate 40% of its electricity from wind by 2020. These targets are comparable with the UK’s. Whether this is realistic is another matter. It remains a firm policy intention with bilateral political support in the Irish Parliament. The Irish system and its experience with wind power integration is especially relevant because of the striking similarity between the two island systems. The following table, which compares the dispatchable generating of the two island systems, is instructive despite being almost three years out of date.
Figure 17
Source: Eirgrid & DUKES Table 5.11 (2010) compiled by the author
Both islands have tiny inter-connector capacity with their neighbours. Only CCGTs have been built since the early 1990s and coal capacity is in decline. Overwhelmingly, CCGTs provide the lion’s share of wind balancing.
215 http://www.eirgrid.com/operations/
Hugh Sharman – Written evidence (REI0006)
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Figure 18
The author has calculated the specific fuel emissions of the CCGT fleet during 2012, before the E-W inter-connector was commissioned and found that the fleet efficiency of ROI’s CCGTs and therefore their specific fuel and emissions costs are substantially lower than nameplate rating of more than 55% (lower heating value).
Figures 19 – 21
Hugh Sharman – Written evidence (REI0006)
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These calculations demonstrate very clearly that even at only 16% annual wind penetration, the average fleet efficiency of the CCGTs is substantially less than nameplate rating, being under 40%, causing high specific fuel costs and CO2 emissions. Furthermore, the anecdotal evidence of serious plant failures is strong. Documentary evidence is scarce because this data is closely held and regarded as commercially sensitive. 6. Conclusions The complete unsuitability of CCGTs for the only remaining task they will have in the UK, as so much more wind power becomes installed, is not yet publicly recognised, although there can be no doubt that the generators understand this well enough. The absence of a willingness to invest in new CCGTs is not just because of the uncertainties of the Electricity
Hugh Sharman – Written evidence (REI0006)
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Market Reform but is driven by the realisation that CCGTs cannot operate profitably in the market being created by so much wind power having priority on the system. The high likelihood of a pending, forced write-down of the 30 GW of the UK’s CCGT capacity, with a replacement value in excess of £20 billion that must be spent by 2020 in order to “keep the lights on” when the wind is not blowing, needs the most urgent public recognition. Technical solutions that are better suited to high wind penetration are being developed but do not yet exist216. However, the need for the early replacement of most of the incumbent 30 GW CCGT fleet will produce another financial shock in the market for which neither UK policy makers nor the public are properly prepared. 18 August 2014
216 Private communication with a retired but still active director of the Danish power sector with unique experience at the top of both power generation and power system operations.
Barrie Skelcher – Written evidence (REI0003)
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Barrie Skelcher – Written evidence (REI0003) Author: Barrie Skelcher, BSc, MSc, MSRC, C Chem, MSRP, MCMI 1 About me. I am 82 years old. I worked for the Atomic Energy Authority 1956 – 1962 and the Central Electricity Generating Board 1962 – 1987. I have experience researching radiation induced chemical reactions, re-processing used nuclear fuel (uranium); managing chemical plants dealing with radio active material; working on a nuclear power station, mainly in radiation safety, environmental monitoring, and emergency planning but also as an unofficial management adviser ; being the local technical officer when the CEGB was proposing Sizewell B to deal with public questions and concerns. My time working for the CEGB, in contact with many different professions, has given me a broad insight into the industry and the following comments are based upon that. Summary. The present electricity infrastructure is very vulnerable and, under present policy, will get worse. It is foolish to generate electricity on a massive scale a long distance from where it is required. The breaking of transmission lines, by accident or deliberate action, would cut supplies for a long time and bring chaos to the UK. 2 Electricity is the life blood of our nation. To loose supply would be akin to a body loosing its blood supply, it would die, may be slowly or may be promptly. Virtually everything we do in modern Britain requires electricity. It is not just “keeping the lights on” candles can do that, it is much more far reaching. Examples, 97% of current money is in electronic format, without electricity it can not be used; transport is electricity dependent, not just rail but lack of electricity would close road signals such as traffic lights and cause accidents and chaos; factories would have to close down; docks would not be able to unload ships; food would rot in refrigerators; radio communications would fail and much much more. It is essential that electricity supplies are maintained. 3. First there must be sufficient generating capacity to meet demand. Electricity can not be stored therefore it is not just a matter of the total generating plant but whether the generating plant will be available to meet the demand. Power stations are not able to generate all the time. They have to be taken out of service for routine maintenance and inspections. They are also subject to occasional breakdown, this may be due to plant failure or external factors. I recall one occasion when a shoal of sprats caused a power station to shut down by blocking its cooling water system! Generally power stations using coal, gas and nuclear will, on average, be available for just over 90% of their time. For this reason, and to ensure a safety margin against exceptional conditions, the old CEGB used to have about a 20% margin of capacity over demand. 4 The deployment of wind and solar power, though desirable to reduce the use of fossil fuels, complicates the situation. Their availability, which is unpredictable, will only be about 30%. Because of their unpredictability they should not be included in the equation of
Barrie Skelcher – Written evidence (REI0003)
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demand versus available capacity. For example, at peek demand times in the winter it is not uncommon for high pressure to settle over the UK for a week or more so reducing wind generation to near zero at a time when solar is low due to weak and short hour daylight. The argument of “If the wind is flat calm over England it will probably be blowing strong in the Outer Hebrides or Orkney” should not be acceptable to argue that it would be ably to supply the becalmed England for reasons which follow. 5 The National Grid connects all the sources of generation and distributes supply across England and Wales as it is required. The system operates on alternating current (ac) so that the electricity can relatively easily be transformed to high voltage for transmission and then transformed to lower voltage for local distribution. The use of ac creates complications that would not exist if direct current (dc) were used. Because of this I am informed that at least one off shore wind farm converts its electricity to dc for transmission ashore. The complications of using ac come into two broad categories as follows 6 Loss of energy in transmission. As the electricity travels along the transmission lines it looses energy, this is not just the classical resistance as for dc but many additional losses because of the nature of alternating current. For example it is in effect flowing backwards and forwards 50 times a second, in doing so it is creating electromagnetic fields the reversing them 50 times a second. As a generalisation about 10% of power is lost for every 50 miles of transmission line. This is why it is not practical to use the power generated by wind farms in the North of Scotland to feed power to the London area. So when equating demand with capacity to generate, the location of the generating sites relative to the areas of demand should be added into the equation. 7 The complex grid system with its many interconnections can go unstable and crash out. Think of it like this. The transmission lines are analogous to hose pipes carrying water. With ac this would means the water in the hose pipe would be going back and forward 50 times a second. The critical factors would be not only the direction but the volume and the pressure. Where other hosepipes connect in their water has to exactly mimic that of the other hose in both pressure and direction. If that were not the case then water could be pushing against water so causing a pressure increase or they could be going in opposite directions so causing a water vacuum. The water flowing down the line has speed and momentum so that as it starts to change direction at one end there would be a slight delay before it starts to change direction at the other end. This is a crude analogy the situation with electricity is much more refined. For electricity think of the amperage as being like the volume of water and the voltage as being like the pressure. Both these have to be tightly controlled especially the voltage, failure to do so could result in massive damage and loss of life at the receiving end. The National Grid is a complex web of linked transmission lines connected to all the sources of electricity generation. To keep the system stable Grid control has to deploy reactive power to keep the voltage and electron flow in phase. They also have to match the demand for electricity with the supply available. For example it has to anticipate changes in demand, the classic being when a popular TV show ends demand jumps up as people get up and put their kettles on and or flush their toilets. For this the Grid will have generating sources on standby ready to pick up this increased load. However if the Grid, when in steady state, suddenly lost, without any warning, a very large amount of generation the system would go unstable and in order to prevent massive surges and depressions the system would shut
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down. In normal conditions this is a very rare event as the Grid can usually survive the sudden lost of a power station that has to shut down through plant failure. However if there was a massive loss of generation, say 20% - 50% of the power being generated the Grid system would crash and virtually all England and Wales would be without electricity. Up to now this has been unlikely to happen because our power stations, which have been the mainstay of the generation of electricity, have been relatively small, For example Sizewell B generates about 1.3GWe, while the demand on the system varies from about 30 GWe to about 60GWe this is a relatively small percentage and robust grid system would survive this. However if present policy is pursued this will not be the case. 8 I will speak mainly about the possible Sizewell C development although other sites such as Hinkley Point, Sellafield, Wylfa, Oldbury, and others, the same considerations will apply. When Sizewell A was built a pair of transmission lines were constructed across the country side to feed the power into the National Grid. That power station was planned to generate about 600MWe although in the event it was down rated to about 450MWe I understand the grid was designed to carry about 2,000MWe at 400kv. This just about allows it to carry the output from Sizewell B and the offshore wind farms. From discussions I have had during consultation periods I understand that if Sizewell C is built its additional power of 3GWe will also be transmitted down this system although the conductors would probably be replaced with heavier ones to carry the extras current. This would mean that 5 GWe or more would be transmitted down these lines, see below.
A natural disaster, or simple terrorist action could easily topple these pylons to crash into each other, they stretch for many miles. If that happened the Grid would loose 5 GWe without any prior notice or warning. This would be between 8% and 16% of the national load! It would most likely cause the Grid to go unstable and blackouts would follow. However if this happened at several sites at much the same time the result would be disaster. The Grid system across the country would go unstable and shut down. Virtually all of England and Wales would be blacked out. This would not just be for a few hours. My guess is that rebuilding the damaged pylon system would take months during which time the country would be denied its life blood. I am so concerned about this aspect of having ultra large generation sites I have written a short novel, it is “The Day England Died” published by the Book Guild & £8.99.
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9 This type of attack would, in the case of large nuclear power stations, have a bonus for the terrorists which I have also mentioned in the novel. If a power station, operating at full power, suddenly looses it connection to the Grid, the reactor does an emergency shutdown. However it still continues to generate a considerate amount of heat from delayed fission and radioactive decay. This has to be removed or the fuel would start to melt out and, even if there was not an off site nuclear emergency, the reactor would be a write off. To provide this cooling the power station needs electricity to drive the pumps providing the cooling water. This power is supplied by standby diesel generators, however if the terrorists found a way of disabling these standby generators disaster would follow. 10 However, with present policy the problem is not just confined to natural disaster or terrorist actions. The present intentions is to have something like 8 nuclear sites, each generating about 4.5GWe, built and operated by foreign companies many of whom are owned or under control of their governments, such as EDF. Should some international diplomatic hassle develop, such as is now happening with Russia, then all the foreign governments would have to do is to instruct the companies to trip their reactors at a preset time without giving National Grid any warning. Again the effect would be devastating as the British Government would have neither the power nor the means to get the reactors operating again. 11 Possible Solutions. The National Grid could be converted to dc. That would stabilise the system but would not solve the problem of shortage of supply from destroyed transmission pylons. It would also produce a large number of other problems which would be costly to solve. It is relatively easy to change voltages with ac but not with dc. The better solution would be to return to the type of system that operated in the 1950’s /60’s. Then relatively small generating stations were near to the areas of demand. For example, I recall that for London there were at least Battersea, Barking, Bank Side, Thurrock, Isle of Grain and probably others. They would all have been connected into the National Grid but that would mainly have been for topping up purposes. Any interruption of supply from sabotage would have been local and relatively easy to overcome. The Day England Died scenario would not have existed. It would be quite possible to return to this style of system, including the involvement of nuclear power stations, but it would require a drastic change in political thinking.
Barrie Skelcher – Written evidence (REI0003)
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12 Power Station size and location would need to be planned on the basis of need for the area and not on which is the most profitable site for the supply company.. This means returning to the type of organisation structure of the old Central Electricity Generating Board, (CEGB). The electricity component of the National Grid would need to be returned to public ownership It would then plan the areas where generation was needed and how best it could be achieved. It could build and operate them itself, as did the CEGB, or it could, having acquired a site, put the construction and operation out to contract. Only in this way could planned generating capacity, availability, site location be maintained in the public interest. 13 Nuclear power. There are serious objections to deploying nuclear power to generate electricity. However, with the situation as it is at present, there appears no other credible option if burning carbon is to be avoided. The problems of deploying nuclear power can be overcome in order to buy time until a better alternative is developed. To deploy nuclear power the following strategy should be adopted. The nuclear stations should be small modular reactor (SMR) types which derive from those used in submarines etc. Rolls Royce has the ability to build such plants. The fuel manufacture should be in public ownership, as it used to be, and Sellafield must be rejuvenated, taken out of the NDA, and tasked to reprocess spent fuel and recover the plutonium for use as reactor fuel. Sellafield should also be tasked in finding a suitable site for the 400 year storage of vitrified fission product waste that they will be producing. The practice being adopted at Sizewell B should be discontinued as it is highly dangerous. The spent fuel should not be dry stored, albeit in concrete sleeves, on the power station site. It would be very vulnerable to terrorist attack. For example, the terrorists would first blow over a couple of the pylons carrying the power from the station. This would cause emergency shutdown of the reactors and the site would have to resort to its own standby generators for essential power to calm the reactor. Using this as a diversifying tactic they then storm the dry fuel store and blow it up so scattering the spent fuel over the area and causing a nuclear emergency. There should be no problem with finding suitable sites for nuclear power stations. The requirement for remote sites no longer applies. For example, Sizewell B has now been declared so safe that the area of the Detailed Emergency Planning Zone (DEPZ) is about to be reduced to less than a mile. The nearby town of Leiston, which used to be under development restrictions (Sizewell B Public Inquiry 1982), has been encouraged to double in population and now has a population density of about 6,800 people/sq km, twice that of Ipswich and greater than that of , by way of example, Norwich. Luton, and Ealing . 26 July 2014
Dr Iain Staffell and Professor Richard Green, Imperial College Business School – Written evidence (REI0056)
603
Dr Iain Staffell and Professor Richard Green, Imperial College Business School – Written evidence (REI0056) Written evidence to be found under Professor Richard Green
Storelectric Ltd – Written evidence (REI0004)
604
Storelectric Ltd – Written evidence (REI0004) Compressed Air Energy Storage in the UK Introduction 1. Renewable energy generation is irrespective of demand: it generates when the weather
is right, not necessarily when needed, and for not generating it when it is needed. This is particularly true of wind power, but also solar, wave and tidal power. Grids’ and electricity generators’ other main problem is supplying sufficient power for peaks and surges.
2. As a result, millions of pounds are paid each year to stop wind farms producing electricity during trough demand217. Millions more are paid to keep power stations (typically gas fired) operating at below 100% efficiency as a “hot standby” that can be fired up at a moment’s notice for peaks and surges. Millions more are paid (in discounted energy charges) to various energy users to permit the generators and grids to switch off parts of their consumption, to reduce the load during peaks and surges, accounting for about 2,000MW costing several thousand pounds per megawatt of capacity regardless of whether or not that capacity is used. They also keep about 500MW of diesel generators and 150MW of gas generators for standby service218. Peak energy sells for up to 5 times the normal wholesale price of electricity.
3. Applying actual winds from January 2000 to the forecast wind farm generation capacity
in 2030, and comparing this with the forecast mix of other generation technologies, shows the scale of the looming problem:
4. While the country will need ~60GW of non-wind capacity for windless days such as 24-27 Jan, most of this is (expensively) unused most of the time. CCGT, for example, only has half of its capacity used four times in the month. However when the wind does blow, even much of the baseload nuclear capacity (which
217 8/1/1: wind farms paid £25m to lose 149,983 MWh http://www.dailymail.co.uk/news/article-2088196/Wind-farms-paid-25million-NOT-produce-electricity-blustery.html Price paid: : £167 per MWh (average) – almost three times the price they would have sold it for; 19/5/13: http://www.express.co.uk/news/uk/400755/Millions-for-wind-power-we-can-t-use From 2011: £26.5m paid to lose 185,000 MWh = £143/MWh; 5/5/1: http://www.telegraph.co.uk/news/uknews/scotland/10038598/Scottish-wind-farms-paid-1-million-to-shut-down-one-day.html EDF charged between £89 to £149 for every megawatt hour (MWh) of energy that was not produced, compared to £50 per MWh the company would have received for selling it.; 17/9/1: http://www.telegraph.co.uk/earth/energy/windpower/8770937/Wind-farm-paid-1.2-million-to-produce-no-electricity.html £1.2M paid to Crystal Rig at £999 /MWh to shut down instead of £100 /MWh for the electricity. 218 http://en.wikipedia.org/wiki/Control_of_the_National_Grid_%28Great_Britain%29#Spinning_Reserve
Storelectric Ltd – Written evidence (REI0004)
605
should never be stopped) has to be stopped 6 times.
5. Therefore, over the years people have proposed diverse schemes to store energy during troughs that they can release during peaks. These have included219: Hydroelectric pumped storage, in which two reservoirs at high and low level are
linked. Water is pumped up during troughs to be released during peaks. About 300 such schemes have been installed world-wide, including Dinorwig (1,728 MW) and Ffestiniog (360MW) in Wales and Cruachan Dam and Foyers in Scotland; two further schemes are under construction in Scotland. However there are not thought to be many more suitable sites available, and those that are suitable are also subject to environmental objections for flooding scenic valleys. They are also very expensive; Dinorwig cost £425m to build in 1974 – equivalent to £3.75bn now220, and current health and safety etc. legislation would double that cost if built anew.
Battery storage has been proposed, but no technology has been demonstrated that offers grid-scale (multi-megawatt) storage capacity. It also suffers from efficiencies of 50-85% depending on the technology: in general, cost rises with efficiency
Cryogenic air or liquid air energy storage is 70% at best, but suffers from both cost and lack of scalability.
Flywheels have been proposed, but the only grid scale plant existing stores 20MW for 15 minutes only and, despite state loan guarantees of $43m, the company developing it went bankrupt221.
Hydrogen fuel cell energy storage is still on the drawing board, and likely to remain there while efficiencies remain around 20-40%. There are also issues of combustibility and scalability.
6. Britain also has many conventional power stations that would operate most efficiently
generating a constant baseload power, but which are used to deliver variable power. If ever energy storage capacity becomes large enough, these can be run constantly with most (if not all) required variation being drawn from the energy storage sites.
7. Finally, once Britain (or any other country, for that matter) has sufficient energy storage
we can power the ever increasing demands of the entire country from renewable sources, protecting the environment and reducing dependency on depleting fossil fuels, pollution and greenhouse gas emissions.
Compressed Air Energy Storage 8. Compressed Air Energy Storage (CAES) is not a new idea, having been proven in Huntorf
in Germany (commissioned in 1978) and in McIntosh, Alabama, USA (commissioned in 1991). Other schemes have been proposed since then but, despite the success of these two schemes, none has gone ahead. It has been proposed on a number of occasions by the British Geological Survey as suitable for many areas of the UK, with suitable salt
219 http://en.wikipedia.org/wiki/Grid_energy_storage 220 Using the Bank of England’s inflation calculator to calculate equivalent prices in 2012 http://www.bankofengland.co.uk/education/Pages/inflation/calculator/flash/default.aspx 221 http://en.wikipedia.org/wiki/Beacon_Power and http://www.beaconpower.com/files/Flywheel_FR-Fact-Sheet.pdf
5.
Storelectric Ltd – Written evidence (REI0004)
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deposits in Northern Ireland, the Irish Sea, and various places around England222, advising the government accordingly.
9. Huntorf currently stores and recovers energy with about 42% efficiency, mainly because
compressing the air loses lots of energy in heat, and re-heating it requires gas heating. There was a project ongoing since 2001 between GE and RWE (the German utility that runs Huntorf) to develop heat stores with the aim of increasing that efficiency to around 70%223, though this project has been stopped. However even at 42% efficiency it is considered a very useful addition to their grid’s capabilities.
10. The technology is completely scalable, since the Huntorf facility uses two small salt
caverns in one of many huge salt fields across Europe, of which there are 10 in the UK onshore, with significant additional offshore extensions in some places and a large basin in the Irish Sea. The smallest of Britain’s salt basins, the Preesall basin across the Wyre estuary from Blackpool, has over 140 existing man-made salt caverns and capacity for many more. The Cheshire and Yorkshire basins are much larger, and also have vacant caverns.
11. Because there is so much salt cavern capacity in the UK, there is no need for any conflict
between applications, for example CAES, gas and hydrogen storage, and other uses such as document and waste storage.
12. We currently estimate that each 0.5GW / 6GWh of storage capacity installation will cost
~ £300m, decreasing sharply for later installations, or about £600/kW and £50/kWh, compared with £2,000/kW and £350/kWh for Dinorwig pumped Hydro (inflation adjusted costs; costs today would be over twice that). First Hydro’s (both Dinorwig and Ffestiniog pumped hydro) valuation is £3.5-5bn. Moreover, we can increase storage very cheaply, at ~£4/kWh.
The Storelectric Proposal 13. Storelectric has patents pending by which we expect to increase efficiency eventually to
70-85%, with the profitability threshold being below 60%. The 40MW / 800MWh pilot plant will be at 62-63% efficiency. We will use existing equipment: well proven, highly reliable and in production, reducing technical risk, which is further reduced by the simplicity of the systems and designs: both Siemens and Oswald Consultancy (consulting engineers) support all this.
14. We currently target an eventual capacity (privately financed) of 27 Gigawatts output and a storage capacity of 3,800 Gigawatt Hours, sufficient for the country’s entire energy reserve, equivalent to 16 Dinorwig power stations, without flooding any picturesque valleys. This technology can also be exported world-wide, putting Britain at the centre of a new global industry. If the British government were to fund the pilot, Siemens are likely to be persuadable to put the first manufacturing plant(s) in Britain.
222 http://www.bgs.ac.uk/downloads/start.cfm?id=1370 from the bottom of p.13. 223 http://www.livescience.com/4955-compressed-air-power-future.html
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15. Storelectric’s consortium already includes Siemens, Pricewaterhouse Coopers and Oswald Consultancy. 3 major civil engineering companies and 2 salt basin operators are keen to join
Cheshire Basin 16. The Cheshire Basin is one of the largest British salt basins. It has also been subjected to
very extensive geological surveys, as there are gas storage facilities within the basin. Local opposition is unlikely due to those existing facilities and the fact that much of the basin is in sparsely populated areas in Shropshire, SW Cheshire and parts of Wales (Wrexham County). On the supply side, it sits centrally to much of the National Electricity Grid as, on the demand side, it is central to the Merseyside, Manchester, Stoke-on-Trent and West Midlands conurbations.
Preesall 17. Solution mining was invented in the Preesall field by the Wyre estuary, north of
Blackpool, creating ~140 salt caverns, of which 6-10 are suitable. Though the smallest UK salt basin, it has considerable capacity for further caverns. Halite has recently done some detailed geological studies for compressed natural gas storage, rejected at planning due to strong local opposition. The leaders of that opposition strongly favour Storelectric’s CAES because compressed air is safe, neither inflammable nor explosive.
18. The Preesall field is onshore from the large Morecambe Bay (Walney) wind farm, currently 104 turbines with an extension in planning. There is a nascent tidal barrage proposal in the adjacent Wyre estuary, which would also improve the flood defences of Fleetwood. On the demand side it is also close to Liverpool and industrial Lancashire.
Future Basins 19. Once a viable and profitable energy storage business is set up, it can be replicated in
other basins around the country, to distribute the storage and load on the National Grid, and to locate storage near to diverse locations of both generation and consumption. It is notable that most British salt basins are just by the coast, near the areas identified for large offshore wind generation, which would mean that our installations can intercept the power generated at landfall so as not to overload the grid when power is not needed.
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British salt basins – British Geological Survey 224 Offshore wind farms, current and planned – The Crown Estate225
World-wide 20. Continental European demand is 5-6 times the UK, with salt basins in most countries.
World-wide demand is 10-100 times the UK, depending on suitably located salt basins.
21. The Yorkshire basin extends to Lithuania, and from north Denmark to north Netherlands
It is the only one of the ten British salt basins large enough to figure on this map, which suggests that there may be 5-10 times the number of suitable basins if we include the smaller ones.
Funding
224 http://www.bgs.ac.uk/research/energy/undergroundGasStorage.html 225 http://www.thecrownestate.co.uk/sustainability/
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22. Government and EU funding may be available (subject to application) to subsidise design and development of a 40 MW, 800M Wh prototype. Development of a 500 MW, 6 GWh complete installation will be privately funded, with expressions of interest already received.
23. This document represents the intentions of Storelectric Ltd at the time of writing, which may change for various reasons including (but not limited to) technical, strategic, political, financial and the wishes of investors. Any person or organisation considering investing in Storelectric does so at their own risk and is responsible for undertaking their own due diligence.
29 July 2014
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Professor Goran Strbac, Imperial College London, The Electricity Storage Network and National Grid – Oral evidence (QQ 102-113) Transcript to be found under the Electricity Storage Network
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UK Energy Research Centre (UKERC) – Written evidence (REI0031) Submitted on behalf of UKERC by: Professor Keith Bell, University of Strathclyde, Dr Paul Dodds, University College London, Dr Modassar Chaudry, Cardiff University, Dr Nick Eyre, University of Oxford and Dr Matthew Aylott, UKERC. The UK Energy Research Centre The UK Energy Research Centre carries out world-class research into sustainable future energy systems. It is the hub of UK energy research and the gateway between the UK and the international energy research communities. Our interdisciplinary, whole systems research informs UK policy development and research strategy. www.ukerc.ac.uk Introduction Ways of viewing electricity system resilience One way of viewing the different influences on reliability of supply of power to electricity users is in terms of three ‘hierarchical levels’: 1. generation (simply, is there enough generation available on the system as a whole to meet total demand); 2. transmission (is the capacity of the transmission network sufficient to allow transfers of power from generation to demand); 3. distribution (are network connections in operation from power sources to each electricity user)226. Electricity transmission in Great Britain is operated as a single, integrated system, with distribution networks connected directly to it. This allows a sharing of reserve generation across the country in both short (seconds to hours) and long (days to years) timescales, the only limitations being: the scheduling of sufficient ‘headroom’ on ‘spinning reserve’, the availability of sufficient short-term ‘standing reserve’, the sufficiency of generation capacity relative to peaks of demand that might be encountered, the location of generation relative to demand and the capacity of the network to permit surpluses of available power in some areas to be used to meet deficits in others. Power network resilience The various network licensees (the transmission owners and the Distribution Networks Operators, DNOs) have licence obligations towards the planning and operation of economic, efficient and secure networks. In particular, rules are defined – ‘security standards’, which the network licensees are obliged to follow – that outline the required level of resilience to disturbances. At a transmission level, this typically (though with some detailed variations) means that the network can still meet all demand for power even if a primary element of the system, such as an overhead line, cable, transformer or generating unit, is suddenly lost from service. Moreover, this should be possible even when other elements of the system are
226 Allan, RN and Billinton, R (1996). Reliability Evaluation of Power Systems. Springer, New York, US.
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already out of service for maintenance. At a distribution level, the level of resilience provided against unplanned outages is lower due to the very large number of circuit km and their cost, and the lower impact of an outage. However, a significant and growing emphasis is placed on rapid restoration of supply following any disturbance that disconnects it (such disturbances on distribution network generally affect only a limited number of consumers). Generation and demand on a network While security standards have been in place for many years and have been applied by the network licensees, achievement of secure supply of electricity depends not only on the network licensees but also owners and operators of generation. Power can only be exported to an importing area if generators are available to produce it. However, the network licensees currently have only a limited influence on the availability of generation or the level of demand that generation should meet. In the longer term, the network licensees have an obligation to make offers of connection to new generators and, if an offer is accepted, to provide and maintain it. In short-term, the National Electricity Transmission System Operator (NETSO, a role filled in Britain by National Grid) can procure, on a commercial basis, availability of generators in critical locations at critical times, provided the generator is not on a forced outage and that sufficient notice has been given. In the longer term, risks associated with prolonged unavailability of key generators must be assessed by the network planner and investments made to increase the network’s power transfer capability, if the risks associated with higher imports to a particular area are judged to be excessive. Similar risks to those associated with unavailability of generation might be linked to higher than expected levels of demand, either in a particular area or on the system as a whole. From year to year and from day to day, the level of demand is affected by the weather. Transmission system operators have generally become good at short-term demand forecasting, but the presence of generation embedded within the distribution networks and not visible to the transmission system operator is making it harder to characterise and forecast the net transfer of power from transmission to distribution. Furthermore, it seems to be the experience in many industrialised countries that longer term (year to year) levels of demand are becoming harder to predict227. Lessons learnt from Ireland The answers provided below concern the electricity system in Great Britain. The system in Northern Ireland is part of a separate electrical ‘synchronous area’ and a separate electricity market – the Single Electricity Market on the island of Ireland. The standards and regulatory arrangements, within which the system in Northern Ireland is planned and operated, are different from those in the rest of the UK and are not discussed in detail below. However, it may be noted that Northern Ireland, while having a significant wind energy potential, has very few schedulable thermal generating units and is therefore more vulnerable, to failure of one or more of those units, than a larger system would be. In order improve security of supply in Northern Ireland, a new 400kV interconnection to the Republic of Ireland has long
227 CIGRE Working Group C1.32 (2014), “Establishing best practice approaches for developing credible electricity demand and energy forecasts for network planning”, Terms of Reference, CIGRE, Paris.
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been planned and would allow sharing of generation capacity228. However, delivery of the line is conditional upon planning approvals both north and south of the border, a process that is made more complicated by the need to satisfy not only both jurisdictions on the island of Ireland, but also European Commission rules on projects of common interest across national borders. This is giving rise to increasing nervousness in Northern Ireland. Meanwhile, as noted, the island of Ireland is operated as one system. It already has, relative to the demand for electricity, a much higher penetration of renewable energy than Britain. As a consequence, the system operator on the island of Ireland arguably has more experience than its equivalent in Britain of the issues associated with, in particular, the variability and low inertia of wind generation. Questions Short term (to 2020) Question 1. How resilient is the UK’s electricity system to peaks in consumer demand and sudden shocks? How well developed is the underpinning evidence base? Generation capacity Experience over a number of decades suggests that the electricity system in GB is highly successful at delivering a reliable supply of electricity. There have been very few instances of significant failures at ‘hierarchical level 1’, i.e. there simply not being enough generation to meet demand. The UK has a peak winter demand of around 60 GW and meets this with around 86 GW generation capacity, plus up to 4 GW from interconnectors to foreign electricity systems. The peak load reserve has eroded in recent years due to the coal and oil thermal generation closure programme mandated by the EU Large Combustion Plant Directive. At the same time, the proportion of renewables in the system has increased and these are less likely to contribute to the peak demand than thermal plants; for example, at the peak time on the peak day in winter 2010, there was virtually no contribution to generation by wind. Yet at present, there is still sufficient thermal and hydro capacity to cover the peak (65 GW) if all of these plants are available. By 2020, as older gas-fired plants are retired as well, the reserve will be further eroded and the contribution of intermittent renewables to meeting peak loads could become increasingly important if new gas-fired plants are not commissioned. In the event of an apparent insufficiency, the system operator does have a number of measures available to them before it becomes necessary to disconnect demand. These include interruption of demand on interruptible demand-side contracts; ‘maxgen’ (thermal generators, in particular, have some capability to operate at a higher than normal output for some period of time); emergency measures on interconnectors to other countries (to reduce export or, if imports are not already at their maximum level, to increase imports); and voltage reduction. Because a power system is both dynamic and highly complex, the timing
228 See, for example, www.eirgridprojects.com/projects/northsouth400kvinterconnectiondevelopment/overview [accessed 19 September 2014].
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of responses can be critical and, under particular circumstances, the system can be on the threshold of complete collapse without rapid intervention. As a result, we believe that ‘defence plans’ should be put in place that, while they might not prevent disconnection of some demand, will limit the amount that is disconnected and enable a much faster restoration of whatever demand was disconnected. These include automatic ‘low frequency demand disconnection’, also called ‘under frequency load shedding’, such as operated during one disturbance in Britain on May 2008229. Although these measures are called upon only rarely, we believe that network planners and system operator should continually ensure that they are available and fit for purpose as the nature of the system develops230. Although it is not strictly part of the ‘defence plan’, one example of the need for periodic review is the performance of voltage reduction. Despite a number of engineers having noted that the nature of electrical loads has significantly changed since the 1980s, when a study of the effectiveness of voltage reduction was last performed in Britain, a new review was only initiated after the May 2008 low frequency disturbance when it was realised that voltage reduction was less effective than assumed. It has been widely observed that much of Britain’s generation fleet is already old and, hence, may be expected to be increasingly unreliable or to require replacement. In the case of nuclear power stations, closure or life extension is the product of judgments made by both the generation owner and the nuclear authorities. For many power stations of different types, the original date of commissioning is not necessarily a good guide to its condition as much of equipment within the station may already have been replaced. Role of gas generation to 2020 for meeting demand peaks The UK is legally committed to delivering 15 per cent of its energy from renewable sources by 2020. To reach this figure it is anticipated that renewables will need to generate at least 30 per cent of the UK’s electricity by 2020231. Wind turbines are likely to play a significant role in achieving these targets but wind is an intermittent source of energy, hence the amount of electricity generated by wind farms is volatile. As cloud cover comes and goes, solar power during the hours of daylight is similarly variable. Such volatility requires other generation to ramp up and down to balance the electricity demand. A future system with much higher wind capacity might be expected to rely heavily on Combined Cycle Gas Turbine (CCGT) power plants to meet the ‘net demand’ not met by renewables. CCGT power plants currently make up a large portion of the total generation capacity in GB at 29 GW in 2013 but this is expected to increase to roughly 35 GW by 2020232. On occasions when wind output is dropping rapidly and demand is increasing, or is constant and high, total CCGT output should ramp up significantly; if sufficient gas storage
229 National Grid (2009). Report of the National Grid Investigation into the Frequency Deviation and Automatic Demand Disconnection that occurred on the 27 May 2008. www.nationalgrid.com/NR/rdonlyres/E19B4740-C056-4795-A567-91725ECF799B/32165/PublicFrequencyDeviationReport.pdf [accessed 27 August 2014]. 230 CIGRE WG C1.17 (2010). Planning to Manager Power Interruption Events, Technical Brochure 433, CIGRE, Paris. 231 HMSO (2010). National Renewable Energy Action Plan for the United Kingdom. Article 4 of the Renewable Energy Directive 2009/28/EC. 232 UKERC (2013). The UK energy system in 2050: Comparing Low-Carbon, Resilient Scenarios. UKERC, London, UK.
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capacity is not provided near to power stations this, in turn, implies a need for high volumes of gas to flow through the network in quite a short space of time. Given that gas supplies from the UK continental shelf have been declining for the past few years, other sources of gas such as liquefied natural gas (LNG), Norwegian and continental gas supplies have been brought online. More storage facilities and linepack (volume of gas in pipelines) management should mollify the actuality of physical gas supply shortages. However, price shock issues are another matter entirely and can be, to a degree, addressed with greater storage capacity, alternatively fuelled power plants, interruptible power contracts and gas demand side management provided interactions with the electricity system are adequately managed233. Quantifying generation capacity resilience Characterisation of the resilience of Britain’s power system depends on computer modelling. This, in turn, depends on appropriate modelling of relevant mechanisms and on suitable input data. In respect of hierarchical level 1 (the kind of analysis reported by Ofgem in its annual assessment of capacity margins), the key inputs are 1. availability of conventional generators; 2. availability of power from wind farms; 3. level of demand peaks; and 4. patterns of flow on interconnectors. There are numerous quantitative measures of electricity resilience. The main purpose of such numerical values is best thought of as helping develop insights into the drivers of energy security rather than to give a prediction of absolute security and reliability in, for example, the coming year. Metrics used to quantify reliability of supply at ‘hierarchical level 1’ use probabilistic techniques and include Loss of Lost Load Probability (LOLP) and the Expected Energy Unserved (EEU):
The conventional meaning of LOLP is a probabilistic weighted average value that measures the likelihood of loss of load234. It does not capture the amount of load that will need to be shed. During the operation of the CEGB (the former nationalised owner and operator of the England and Wales electricity network and generation), a LOLP of 0.09 was considered the standard235, i.e. the probability of peak load not being supplied was 9%. A complementary metric is Loss of Load Expectation (LOLE) which quantifies the expected number of hours per year in which supply does not
233 The PJM electricity system in North America experienced severe challenges in the winter of 2013/14 as a result of the ‘polar vortex’ that brought much colder weather than normal for an extended period of time. One result was that electricity demand on some days was around 33% higher than on a typical winter day. The challenge was compounded by gas demand for heating being much higher than normal and the gas system operator responding by interrupting gas demand on interruptible contracts. This included CCGT power stations. In combination with forced outages of generating plant influenced by the extreme cold weather, this resulted in a combined generation forced outage rate on January 7, 2014 of 22% compared with the historical winter average of 7%. See Keech, Adam (2014), 2014 Winter Conditions and Impacts on Electricity Markets in the PJM Region presented at CIGRE 2014, Paris, www.cigre.org/Events/Session/Session-2014/Documents-download-for-Delegates [accessed 05 September 2014]. 234 Allan, RN and Billinton, R (1996). Reliability Evaluation of Power Systems. Springer, New York, US. 235 Strbac, G, Pudjia, D, Castro, M, Djapic, P, Stojkovska, B, Ramsay, C, and Allan, R (2007). Transmission Investment, Access and Pricing in Systems with Wind Generation: Summary Report www.ofgem.gov.uk/ofgem-publications/55765/dti-centre-dg-and-sustainable-electrical-energy-paper.pdf [accessed 19 September 2014].
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meet demand. However, both DECC236 and Ofgem237 qualify this by referring to failure to meet demand in the absence of intervention from the System Operator where the interventions include controlled voltage reduction, ‘maxgen’ by generators, emergency services from interconnectors and controlled disconnections. In other words, LOLE is regarded by Ofgem as the number of hours in which these interventions may be expected to be required; in general this will be greater than the number of hours in which uncontracted customer disconnections will occur.
The EEU for any particular period (day, week, year etc.) gives the probability weighted magnitude of interruption to energy supplies (loss of load). A cost of EEU can be estimated by multiplying the EEU with a given value of lost load (VOLL).
Monte Carlo modelling techniques can be used to calculate the reliability (LOLP, LOLE, EEU) of the electricity supply system. A model built specifically for this purpose has been commissioned by UKERC and will be used to quantify the impact on the reliability of the GB gas and electricity infrastructure due to energy uncertainties such as wind variability, gas supply availability and outages to network assets (generation plants and transmission network).238 Doubts have been expressed in respect of the quality of data for all of the inputs to a reliability quantification outlined above239. Estimates of peak demand in recent years have tended to exceed those experienced in reality, and future estimates are made more difficult by uncertainties in the extent of demand side response (load shifting in time) as smart metering and time of use tariffs become prevalent. Particular concerns have been raised in some quarters that the potential contributions of interconnector imports are being under-represented in analyses being undertaken by National Grid as part of the process for determining requirements in the future GB capacity mechanism240. The claimed result of this is that the cost of generation capacity will be excessive. As minimum, we would argue here that what is required is a clear understanding on all sides of what the reliability standard represents against which generation capacity is being procured. For example, is it the likelihood of disconnection of demand that does not have a contract in place allowing it or some part of it to be disconnected? Or does it represent the likelihood of system operator action being required to manage the shortage of generation relative to demand where such actions include emergency re-dispatch of flows on interconnectors?
236 DECC (2014), The Electricity Capacity Regulations 2014, www.gov.uk/government/uploads/system/uploads/attachment_data/file/249564/electricity_capacity_regulations_2014_si.pdf [accessed 05 September 2014]. 237 Ofgem (2014). Electricity Capacity Assessment 2014: Consultation on Methodology. www.ofgem.gov.uk/publications-and-updates/electricity-capacity-assessment-2014-consultation-methodology [accessed 27 August 2014]. 238 Chaudry, M, Wu, J and Jenkins, N (2013) A sequential Monte Carlo model of the combined GB gas and electricity network, Energy Policy 62:473-483. 239 Ofgem (2014). Electricity Capacity Assessment 2014: Consultation on Methodology. www.ofgem.gov.uk/publications-and-updates/electricity-capacity-assessment-2014-consultation-methodology [accessed 27 August 2014]. 240 Newbery, D and Grubb, M (2014), The Final Hurdle? Security of supply, the Capacity Market and the role of interconnectors. University of Cambridge.
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Transmission and distribution networks Electricity demand interruptions experienced in Britain over the last few decades have generally been associated with network outages. Single circuit outages are not uncommon at a distribution level but, as noted above, their impact is generally limited241. Because of the design of the transmission network, disconnections of demand originating at a transmission level are relatively rare242 even though 100 single circuit faults might occur in a typical year on the GB transmission system; around half of them due to adverse weather243, such as lightning, very high winds or sleet, snow icing or blizzards. The most significant events are generally associated with storms that lead to multiple outages in a short space of time, and often to damage of equipment that takes time to repair. Trees and other debris falling on roads, so hindering access to key locations and faults on communications networks, often compound the difficulty of achieving safe and rapid restoration of supply. Issues around recovery from major electricity system disturbances are receiving increasing attention worldwide not least in view of the need to coordinate the responses of multiple parties244. The underlying resilience of the power system to adverse or extreme weather is very difficult to determine. While past experience suggests that conventional ‘N-1’ transmission design and operation rules do deliver a resilient system245, extreme weather is, by definition, rare and any conclusions relative to past performance cannot be regarded as completely robust. Of particular concern should be relatively rare ‘common mode’ failures, such as very high winds that cause large numbers of wind turbines to shut down, ‘type faults’ on generators, i.e. those consequential to the design and may, as a result, be expected to affect other generators of the same type, or double circuit or substation faults on the transmission network. Particularly severe examples of the last of these started to receive increased attention in recent years following the floods in Gloucestershire during 2007. As already noted, the most severe network disturbances occur either when there are multiple faults within a short space of time, such that earlier outages have not yet been restored before further outages occur, or that a single, very rare event leads to the loss of multiple system elements. The net result is that the system’s state is worse than the ‘N-1’ under which it was designed to still have acceptable operation. Hence, while both cases have quite low probability of occurrence, they have quite high impact. Analysis of such situations is difficult and not helped by wide variability in the quality of outage statistics. This includes generator availabilities mentioned above but also statistics on fault rates and outage durations for network components such as overhead lines, underground cables, 241 See www.ofgem.gov.uk/electricity/distribution-networks/network-price-controls/quality-service/quality-service-incentives for DNO performance in respect of ‘customer minutes lost’ and ‘customer interruptions’ [accessed 19 September 2014]. 242 See www2.nationalgrid.com/UK/Industry-information/Electricity-transmission-operational-data/Report-explorer/Performance-Reports/ for reports of performance on the GB electricity transmission system [accessed 19 September 2014]. 243 Murray, K & Bell, KRW (2014). Wind Related Faults on the GB Transmission Network. Proceedings of the 13th International Conference on Probabilistic Methods Applied to Power Systems, Durham, 07-10 July 2014. 244 Southwell, P (2014). On behalf of the CIGRE Technical Committee, Disaster Recovery within a Cigre Strategic Framework: Network, Resilience, Trends and Areas of Future Work. CIGRE, Paris. 245 ‘N-1’ refers to the state of the system in which one element is out of service, ‘N-2’ when two elements are out and so on. Alternatively, in some countries, the ‘1’ in ‘N-1’ refers’ to an outage event that might actually cause the loss of more than one element.
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transformers, circuit breakers and bus sections. To be of greatest value to modelling of system performance, outage causes and restoration times should be consistently noted. As reported in Murray & Bell (2014), some transmission network licensees in Britain do better than others in this respect. A high proportion of Britain’s power network assets are already more than 40 years old, sometimes more than 60 years old. Much of it may therefore require investment in replacements. Since the associated outages are longer than for routine maintenance, depleting the network’s capacity in the meantime, this requires careful planning. However, in many cases it is found that assets older than their planned life are still in reasonable condition and it is not necessarily the case that new assets will more reliable or have similar longevity. The relationship between generators and network operators One thing noted by CIGRE WG C1.17 was the dependency on multiple actors to deliver a resilient power system. As well as providing active power, generators are critical to the regulation of system frequency and the provision of reactive power to support voltage. In a liberalised electricity supply industry such as that in Britain, generators are owned and operated independently of the system operator. In many countries, experience shows that grid codes that define generators’ responsibilities towards the system and, in some countries such as Britain, markets for system balancing services, succeed in ensuring that the system as a whole can be operated reliably. However, on occasions, it is found that not all equipment performs as it should. Network licensees are responsible for the performance of network equipment and can intervene directly to maintain adequate performance. However, the system operator responsible for system performance is not responsible for whether generation equipment performs correctly, and failures of generator systems have sometimes been implicated in major system disturbances around the world246. The network licensees in Britain have a number of incentives to improve performance in respect to reliability of supply. The main incentive for generators is to be available to generate in order to gain revenues from the sale of energy. Under the proposed capacity mechanism, generators would not only receive an income from actual operation and production but also from being ready to operate. In some categories of short-term reserve, a similar arrangement already exists. For DNOs, there is an incentive to reduce ‘customer interruptions’ and ‘customer minutes lost’. For the transmission owners, the average annual availability of circuits is reported along with the estimated energy not supplied as a consequence of transmission faults. A major, but not the only, influence on these indices comes from the management of the various assets, where benefits of maintenance must be balanced with the cost of maintenance and the impact on the system of an asset being out of service while it is maintained. For older assets, where maintenance is increasingly difficult (perhaps because of the obsolescence of components) or expensive and the asset is still required on the system, replacement of asset becomes necessary.
246 CIGRE WG C1.17 (2010). Planning to Manager Power Interruption Events, Technical Brochure 433, CIGRE, Paris.
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Question 2. What measures are being taken to improve the resilience of the UK’s electricity system until 2020? Will this be sufficient to ‘keep the lights on’? The main challenges identified by the Committee on Science and Technology Committee’s Call for Evidence on the Resilience of Electricity Infrastructure are the:
Closure of ageing power stations;
Decarbonisation of electricity, largely by means of renewables and nuclear power which the Committee says will be less flexible than fossil fuelled plant.
The inability to schedule wind or solar power, their variability, the low inertia of sources of power that use power electronic interfaces and the relative inflexibility of some of the leading designs of nuclear power stations means that: (a) renewables cannot be depended on to meet peak demand; (b) the ‘net demand’ not met by renewables and nuclear power will be highly variable and requires some very flexible means of meeting it; and, (c) losses of power infeed (i.e. supply of power to the system, under high wind, solar or import conditions) would lead to rapid changes of system frequency and, without adequate countermeasures, risk of frequency instability. The measures being taken that can contribute to resilience of the power system include:
Introduction of a capacity mechanism.
Interest by investors in development of new interconnectors.
Development of balancing service arrangements to encourage demand side response.
Expansion of the number of aggregators offering demand side services.
Continued incentivisation by Ofgem of distribution network operators (DNOs) to maintain quality of service as measured in terms ‘customer interruptions’ (CI) and ‘customer minutes lost’ (CML).
Securing of ‘Network Innovation Competition’ (NIC) funding by Scottish Power Energy Networks for the ‘Visualisation of Real Time System Dynamics using Enhanced Monitoring’ (VISOR) project.
Proposed NIC project on the management of system stability on a system with greatly increased production of power from wind energy, from National Grid Electricity Transmission and partners.
While the above initiatives are welcome, we believe there are some open questions, among which are the following:
1. Is the reference reliability level proposed for use in the capacity market set appropriately given different stakeholders’ interpretation of it and the likely costs of procuring the requisite volume of capacity247?
2. Will the mechanism by which capacity is planned to be procured in the capacity market both deliver sufficient capacity and be cost-effective?
3. How should potential contributions to long-term security of supply from international interconnectors be treated in the capacity market?
4. Is it appropriate that development of international interconnectors to and from Britain is left solely to private ‘merchant’ investors when most other European
247 See the discussion of reliability metrics under Question 1.
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countries see it as a responsibility of the regulated transmission system operator (TSO)?
5. What more can be done to deliver the large potential for Electricity Demand Reduction already identified by DECC?248
6. What are the main blocks to development of demand side response that can help with electricity system in real-time and how can they be overcome?
7. Does National Grid Electricity Transmission as operator of the GB electricity system have sufficient expertise to manage a system with very high penetrations of low carbon in the most economic manner possible?
In respect of question 3 above, it may be noted that some academic studies have estimated that electricity consumers in Northern Europe could save around €50 million per annum if reserve generation is allocated optimally across the region and has access to interconnection capacity249. Issues around the potential value of such provision to the UK and market delivery mechanisms are currently being investigated by UKERC. Questions 5 and 6 arise from many years of academic assertion of the value of energy efficiency and demand side response. Efforts in the former area have declined since the exclusion of lighting and appliances programmes from supplier obligations. There has been slow development of demand side response in Britain which may be speculated to be due to failure of the big retailers to offer products that include it, the relatively small financial gains for many consumers or the inconvenience it might entail. In respect of question 7, it may be noted that while the capacity market is designed to ensure that sufficient generation is available, its utilisation depends on the system operator250. Although, fortunately, its occurrence is rare, the scope for human or equipment errors on the transmission system to turn a minor disturbance into a system blackout has been well-established251. National Grid Electricity Transmission (NGET) is obliged to comply with the Security and Quality of Supply Standard (SQSS) when operating the system and is also incentivised to keep the costs of doing so at a minimum. NGET’s general success to date in ‘keeping the lights on’ has been discussed above. It has a well-developed set of procedures and analysis facilities to support this. However, the nature of the system with more wind and solar power than at present will be quite different and established tools and procedures may prove insufficient. Although we understand NGET to be investing in new software for the implementation of balancing services, we are not aware of the company having undertaken
248 www.gov.uk/government/uploads/system/uploads/attachment_data/file/66564/7035-capturing-full-elec-eff-potential-edr.pdf [accessed 19 September 2014]. 249 See, for example, Gebrekiros, Y and Doorman, G (2014). Optimal Transmission Capacity Allocation for Cross-border Exchange of Frequency Restoration Reserves (FRR), Proc. 18th Power Systems Computation Conference, Wroclaw, August 18-22, 2014. 250 Some issues around scheduling and utilisation of reserve are discussed in Bell, KRW (2014). Response to Electricity Capacity Assessment 2014: Consultation on methodology, available www.ofgem.gov.uk/publications-and-updates/electricity-capacity-assessment-2014-consultation-methodology [accessed 08 September 2014]. 251 See, for example, CIGRE WG C1.17 (2010). Planning to Manager Power Interruption Events, Technical Brochure 433, CIGRE, Paris.
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a systematic study of future system operation in a manner similar to that of Eirgrid on the island of Ireland which faces comparable challenges of operating an island system with high penetration of wind, and note the challenges faced by the industry in the recruitment and retention of leading engineering expertise252. While NGET might reasonably look to UK academics to help inform it, independent researchers are hindered in being able to make material observations on the GB system through lack of access to realistic data in practice253. Moreover, some funding sources such as the Network Innovation Competition require a cost-benefit analysis as part of a research proposal and this can impede novel and radical research into electricity system resilience in which such cost-benefits cannot credibly be justified at the outset. We question whether research funding from the various sources could be more holistically coordinated to encourage better and more fruitful collaborations between industry and academics, for finding better solutions to resilience issues on shorter and longer timescales. Question 3. How are the costs and benefits of investing in electricity resilience assessed and how are decisions made? It has been noted above that debate about the costs and benefits of the proposed capacity market continues. For transmission network investments that facilitate access to available generation in different locations, contributing to security of supply, some long-established rules written in the SQSS determine what level of transmission capacity should be provided. However, as far as we are aware, the last time the costs and benefits associated with these rules was assessed in the Review of Security Standards conducted in the 1990s. Our opinion is that, when applied for a given background of operational generation and forecast demand, the rules that there should not be under-investment though whether the associated level of network capacity is economically optimal is open to question. However, the SQSS as currently written provides little guidance on the risks associated with uncertain generation background though it may also be argued that the introduction of the capacity market will reduce the level of uncertainty. In addition, the rules provide little guidance on high impact events such as flooding. In respect of local network resilience at a distribution level, Engineering Recommendation P2/6 (ER P2/6) defines the minimum requirement to be satisfied by DNOs. We understand it to have been based on a cost-benefit analysis undertaken in the 1970s. In light of changes to the use of electrical energy since then, this may be judged to be due for review and, indeed, a review of ER P2/6 has been initiated by the Energy Networks Association. However, our understanding is that DNOs are against wholesale changes. Nonetheless, the CI and CML incentives may be argued to provide a sufficient backstop provided the DNOs are capable of undertaking the associated analyses. In addition, while the CI and CML incentives should
252 Bell, KRW, Fenton, W, Griffiths, H, Pal, BC and McDonald, JR (2012). Attracting Graduates to Power Engineering: Successful Industrial Engagement and Collaboration in the UK, IEEE Trans on Power Systems, vol. 27, no. 1, February 2012. 253 Bell, KRW and Tleis, AND (2010). Test system requirements for modelling future power systems, IEEE Power & Energy Society General Meeting, Minneapolis, July 2010.
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help manage long-term expectations of reliability of supply, appropriate measures to manage the impact of relatively rare events such as severe storms are harder to evaluate and Ofgem has recently called into question some DNOs’ performance in restoring supply lost in storms in the winter of 2013/14254. Question 4. What steps need to be taken by 2020 to ensure that the UK’s electricity system is resilient, affordable and on a trajectory to decarbonisation in the following decade? How effective will the Government’s current policies be in achieving this? As indicated under Question 2, the steps outlined, in particular the introduction of a capacity market and incentives on distribution network operators (DNOs) in respect of customer interruptions (CI) and customer minutes lost (CML), promise to make significant contributions to electricity users’ reliability of supply but, as also outlined above, there are some key related questions that are yet to be fully answered not least in respect of the cost of the capacity market. Other aspects of Electricity Market Reform are intended not only to facilitate investment necessary to achieve further decarbonisation but to do so cost-effectively, although UKERC research shows that EMR has not been designed adequately to incentivise electricity demand reduction255. It remains to be seen whether an adequate balance will be struck between facilitation of investment and management of the cost to consumers, with doubt having been cast over the contract signed for the development of Hinkley Point C256 and the proposed contracts for difference for offshore wind257. One of the features of the UK’s energy system that makes the achievement of the objective of a resilient, affordable and progressively decarbonised energy system a particular challenge relative to that in some other countries is the fragmentation of the industry, largely as a consequence of the introduction of competition in energy wholesale and retail. This means that as well as the market and policy initiatives outlined above, the Government has a key role to play in coordinating responses to emergencies among many different parties – system operators, generators, network owners and emergency services258. It always has been and remains imperative that this takes a whole energy system perspective. For example, as noted above, the gas and electricity system are already inter-related and will become more so. In addition and as was observed at Fukushima, the safe operation of
254 Ofgem (2014). December 2013 storms review – impact on electricity distribution customers, available www.ofgem.gov.uk/ofgem-publications/86460/finaldecember2013stormsreview.pdf [accessed 10 September 2014]. 255 Eyre, N (2013). Energy Saving in Energy Market Reform - The Feed-in Tariffs Option. Energy Policy 52 190-198. 256 European Commission (2013). State aid: Commission opens in-depth investigation into UK measures supporting nuclear energy http://europa.eu/rapid/press-release_IP-13-1277_en.htm [accessed 19 September 2014]. 257 MaCaffrey, M (2014). Allocation, allocation, allocation www.renewableuk.com/en/blog/index.cfm/id/01112537-6D02-420D-95B513F2F9958AE0 [accessed 19 September 2014]. 258 See DECC (2014). Preparing for and responding to energy emergencies, www.gov.uk/preparing-for-and-responding-to-energy-emergencies [accessed 14 September 2014].
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nuclear power stations depends on the integrity of its power supplies which normally come from the transmission system with back-up from on-site generation259. Among private sector actors in the energy system in Britain, National Grid is arguably the single most important player in respect of system resilience. It is responsible for operation of the gas and electricity transmission systems, planning and development of National Transmission System for gas and planning and development of the onshore electricity transmission system in England and Wales. The Government has also given it responsibility for implementation of key aspects of Electricity Market Reform including the capacity market. National Grid was given a highly challenging settlement by Ofgem in the most recent transmission price control260. According to Ofgem, “New price controls for transmission and gas distribution networks took effect in April 2013 and are designed to keep the pressure on the network companies to deliver value for money”261. Faced with the need to maintain its profitability, not least in order that it can raise adequate funds on capital markets to support future network investment sufficiently cheaply, we understand that National Grid has responded by conducting a fundamental review of its structure and has dispensed with a substantial number of management and engineering posts. Given the company’s central role in administering so much of Britain’s energy system at a time of considerable economic and technical challenges, it may be reasonable for the Committee to seek reassurance and evidence from National Grid that key expertise and experience have not been lost. Moreover, Ofgem might also be asked if particularly challenging settlements entail any medium-term risks to delivery of a secure, affordable and decarbonised energy system. Question 5. Will the next six years provide any insights which will help inform future decisions on investment in electricity infrastructure? The next six years promise to provide important insights in respect of the following:
Operation of the GB capacity market;
Take-up and cost of contracts for difference for low carbon generation;
Impact of the EU’s Industrial Emissions Directive (IED)262;
Government policy, including targets, for decarbonisation post-2020;
Increasing intermittent renewable capacity, forecast by National Grid to be 20 GW by 2020, which are likely to lead to more periods of excess supply and greater supply variations, and well as more volatile electricity market prices.
259 At Fukushima, the same disturbance that broke the connection with the transmission network also rendered standby diesel generators unusable. See, for example, Strickland, E (2011), 24 hours at Fukushima, IEEE Spectrum, vol. 48, issue 11. 260 Ofgem (2012), RIIO-T1: Final Proposals for National Grid Electricity Transmission and National Grid Gas – Overview, www.ofgem.gov.uk/publications-and-updates/riio-t1-final-proposals-national-grid-electricity-transmission-and-national-grid-gas-%E2%80%93-overview [accessed 14 September 2014]. 261 www.ofgem.gov.uk/about-us/how-we-work/promoting-value-money [accessed 14 September 2014]. 262 www.defra.gov.uk/industrial-emissions/eu-international/industrial-emissions-directive/ [accessed 14 September 2014].
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We do not attach a very high probability to the development of significant levels of active demand side participation in energy markets, the purchase and use of numerous electric vehicles or a significant increase in electric heating in the next six years. However, those things may ramp up in the period after 2020. A development on which Ofgem has been working in the last few years, which may be expected to result in some concrete recommendations in the next year or two and which will affect the way in which investment in the electricity infrastructure is carried out is “Integrated Transmission Planning and Regulation” (ITPR)263. Among other things, this might force a separation of electricity network operation, planning, and asset procurement, construction and maintenance activities across the whole of Britain. (Electricity system operation (SO) is currently separated from the other activities in Scotland and offshore, those other activities being generally integrated within a single ‘transmission owner’ (TO) in a particular geographical area). A potentially important new initiative originating within the UK’s engineering community is the idea of a ‘system architect’264. This has been motivated by recognition of the interconnectedness of the energy system and the fragmentation and complexity not only of the industry’s commercial structures but also of its technical standards. As we understand it, the intended role of the ‘system architect’ is not one of central planner or ‘chief engineer’ but one of a panel that reviews industry and system developments to ensure that they work successfully in a complementary manner. Medium term (to 2030) Question 6. What will affect the resilience of the UK’s electricity infrastructure in the 2020s? Will new risks to resilience emerge? How will factors such as intermittency and localised generation of electricity affect resilience? Evolving electricity demands Current electricity consumption is unlikely to reduce significantly. In the medium term, climate change is likely to increase the air conditioning load; cooling is responsible for 4 per cent of the total UK electricity demand and in London alone demand for cooling is expected to double by 2030, to nearly 3 TWh per year.265 In the longer term, decarbonisation of heat and transport must greatly accelerate, and one strategy would be by electrification of large parts of the energy used for heating or transport. This would significantly increase the demand for electricity and would change its time-of-use profile, placing ever increasing pressures on the electricity system. For example, UKERC research shows that complete
263 www.ofgem.gov.uk/electricity/transmission-networks/integrated-transmission-planning-and-regulation [accessed 14 September 2014]. 264 IET Power Network Joint Vision (2013), Electricity Networks: Handling a Shock to the System. 265 Day, AR, Jones, PG & Maidment, GG (2009). Forecasting future cooling demand in London. Energy and Buildings, 41, 942-948.
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decarbonisation of heat might add 40 GW to peak demand, even using efficient heat pumps.266 Impact of localised and intermittent electricity generation on networks By 2030, there could be more than 40 GW of intermittent renewables, primarily wind generation, in the UK. National Grid forecast that the proportion of generation connected to the distribution networks could almost double to 20 GW in this time.267 If generation is located close to demand or even on the same site as demand, e.g. domestic solar panels, it might simplistically be assumed that this reduces the need for the network. However, much of this generation capacity is expected to be based on intermittent renewables; reliable access to electric power therefore depends on either the network or storage. Other generation capacity might come from combined heat and power, the operation of which is largely heat-led and which might have a large surplus of electric power at times that are, from the perspective of power system operation and local network capacity, inconvenient. Moreover, if current institutional arrangements continue: (a) much of this generation capacity, embedded within the distribution network, will be visible to the transmission system operator only to the extent that it reduces that net demand; and, (b) the Distribution Network Operator (DNO) will have little or no influence over its output and its effect on the rest of the system. It has been widely supposed that ‘smart’ measures will, relative to conventional means, prove more cost-effective in meeting the challenges of providing a reliable supply of electricity on a future power system, which has high demand and large quantities of highly variable renewable generation alongside what may be expected to be relatively inflexible nuclear power.268 This effectively means that the need for primary network capacity269 or reserve generation can be reduced by greater use of ‘post-fault actions’, which correct the consequences of faults instead of providing such margin on the system, preventing adverse consequences of disturbances; in so doing, better use is made of the available primary capacity. These post-fault actions include rapid re-dispatching of generation and, in particular, demand-side responses. Given that most demand is connected on distribution networks and with the expected growth of generation embedded within the distribution system (sometimes called ‘distributed generation’), if investment in primary assets is to be minimised and elements of the distribution network are not to be overloaded and voltages are to be kept within acceptable limits, DNOs will need to become more active operators of their networks, essentially becoming Distribution System Operators (DSOs). This will require more network monitoring, greater volumes of data and more involved decision making. If this and the
266 Eyre, N. and Baruah, P. (2014) Uncertainties in Energy Demand in Residential Heating. UK Energy Research Centre Working Paper. 267 National Grid (2013) Electricity Ten Year Statement, http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Electricity-ten-year-statement/Current-statement [accessed 19 September 2014]. 268 UKERC (2014). Scenarios for the Development of Smart Grids in the UK. UKERC: London, UK. 269 By ‘primary network capacity’, we mean that provided by high voltage assets rather than ‘secondary’ assets that provide monitoring and control.
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interactions with transmission are not adequately managed, all these factors could make the uncertainties experienced by the transmission system operator worse. Medium-term network system stability Increasing reliance on post-fault, corrective actions makes a system operator’s job more complex. While transmission system operation, in particular, already makes use of extensive automation and decision support software systems, new systems will need to be introduced. Moreover, with such dependence on corrective actions, monitoring and actuation should be extremely reliable which is likely to require redundancy to improve performance but which would not guarantee success. Power systems are large, dynamic and complex. The benefits of networks in allowing local surpluses or deficits of power to be balanced out270 also permit disturbances to be propagated widely and very rapidly (on a scale of milliseconds). The system operator therefore also needs to be cognisant of the state of the system as a whole. Automated protection systems have, for many years, helped to manage the propagation of disturbances. Major regional or system blackouts around the world have often associated with failures of protection or of system monitoring and decision making; reduction of system margins and greater reliance on corrective actions arguably make such events more likely in future and make the ‘defence plans’ mentioned earlier more important. The risk of cascading outages has received some attention from electricity regulators in the US and from academics, but there remain significant challenges in reliably quantifying the risk271. Longer-term impacts of climate change It has been shown that climate change is already leading to changed weather patterns and that power system design standards might not be sufficient to continue to deliver the levels of reliability of supply of electricity to which society has become accustomed. The ways in which changed weather might impact on the power system include the following:
Increased ambient temperatures in summer leading to: o De-rating of transformers and cables, which has been predicted to increase by
up to 12 per cent by the 2080s272. o Lower efficiency of gas turbines as a consequence of reduced air mass flow,
resulting in a loss in power output of up to 0.5 per cent for every 1°C increase in ambient air temperature.273
o Potential for increased air conditioning load274.
270 For the most part, storage still does not compete with network capacity economically as an alternative way of smoothing out imbalances. 271 Vaiman, M, Bell, KRW, Chen, Y, Chowdhury, B, Dobson, I, Hines, P, Papic, M, Miller, S, and Zhang, P (2012). Risk Assessment Methodologies for Cascading Outages. IEEE Trans on Power Systems, vol. 27, issue 2, 2012. 272 McColl, L, Angelini, T & Betts, R (2012). Climate Change Risk Assessment for the Energy Sector: Technical Report. London: Department for Environment, Food and Rural Affairs (Defra). 273 Kakaras, E (2006). Inlet Air Cooling Methods for Gas Turbine Based Power Plant. ASME, 128, 312-327.
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Increased concentrated rainfall leading to increased risk of flooding; estimates suggest a 79% increase in the number of power stations at risk and a 21% increase in the number of substations at risk by 2050275.
More severe winters with increased risk of ‘wet snow’ or icing of overhead lines and insulators and, hence, increased likelihood of electrical faults; icing of overhead line conductors leading to risk of mechanical failure; increased snowfall coinciding with high winds and causing electrical faults.
More frequent occurrence of electrical storms and hence of lightning causing fault outages.
More frequently occurring or more severe high wind events with increased likelihood of short-circuit faults and, if the highest wind speeds are very high, mechanical failure of overhead lines or wind turbines.
Colder winters leading to higher heating demand. The Climate Change Act 2008 and the Climate Change (Scotland) Act specified that a UK-wide Climate Change Risk Assessment (CCRA) be carried out every five years. The first of these were published in 2013 and looked at 11 key sectors including energy (McColl et al., 2012). The report recognised that much of the methodology was top-down, impacts led and reductionist and did not fully develop socio-economic scenarios, behavioural aspects of change, complex systems, non-linear changes and systemic risks, but was the first major attempt to rigorously quantify the risks posed by climate change to energy infrastructure. In July 2013, the UK Government published its first National Adaptation Programme (NAP), which was developed as a response to the CCRA and will also be produced every five years. The NAP is the Government’s long-term strategy to address the main risks and opportunities identified in the CCRA. The programme focuses on the following key areas: raising awareness of the need for climate change adaptation, increasing resilience to current climate extremes, taking timely action for long-lead time measures, and addressing major evidence gaps. The Adaptation Sub-Committee of the Committee on Climate Change is due to report to Parliament on the progress made in the implementation of this programme in 2015. On infrastructure, the ASC will cover energy, ICT, transport and water, and will report on the level of exposure to a range of climate hazards, as well as the level of resilience action occurring in each sector. Further to this, the network licensees in Britain commissioned two studies from the UK Meteorological Office that have explored temperature rise and the possibility of increased occurrence of faults. However, the latter, in particular, gave little clear insight because: (a) there are limitations in the modelling of future weather; and, (b) the correlation between fault rates and demand interruption on a transmission network is not linear. Some academic studies have been commissioned more recently to look at the possible effects of climate change on power network assets, such as RESNET, ITRC and PURE, and on reliability of
274 UK Power Networks (2014). Business Plan (2015 to 2023) http://library.ukpowernetworks.co.uk/library/en/RIIO/Main_Business_Plan_Documents_and_Annexes/UKPN_Climate_Change_Adaptation.pdf [accessed 19 September 2014]. 275 Byers, EA, Hall, JW, and Amezaga, JM (2014). Electricity generation and cooling water use: UK pathways to 2050. Global Environmental Change, 25, pp16-30.
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supply276. However, the complex system of governance, acting at a number of scales, in the UK still poses a significant challenge to the response of the energy industry to the impacts of climate change – especially in the long term. Changes in political priorities for different sectors can lead to conflicting demands on infrastructure providers. Addressing these conflicts will be of critical importance in the future and needs integration into national adaptation strategies. Question 7. What does modelling tell us about how to achieve resilient, affordable and low carbon electricity infrastructure by 2030? How reliable are current models and what information is needed to improve models? See discussion under question 1 in respect of models and information and Question 6 on quantification of the risk of cascading outages. In addition to what was mentioned above, it may be noted that there is currently no robust information on how reliable ‘smart grids’ and demand side management (DSM) might be. UKERC is undertaking various studies as part of its future research activities. This will include energy system modelling, assessments of the energy, material and water resources required for energy systems, and their ecosystem impacts, research on the political economy of international resource flows and economic, engineering and policy assessments of the interactions, synergies and trade-offs between the large-scale deployment of electricity, hydrogen and heat. Explicit attention will also be paid to the social and environmental dimensions and implications of different energy system configurations. Question 8. What steps need to be taken to ensure that the UK’s electricity system is resilient as well as competitively priced and decarbonised by 2030? How effective would current policies be in achieving this? We identify some of the important technologies that could improve the resilience of the electricity system in Question 9. The electricity system does not operate independently of other parts of the energy system and is likely to become increasingly integrated in the future. There is very little energy storage in the current system; precursors to electricity generation are stored, such as natural gas, and generation is continuously modified to meet electricity demand. In the future, there could be much higher demand peaks and much more inflexible generation, including periods with supply exceeding demand. These changes would necessitate either the use of energy storage technologies, deployment of DSM or a great increase in generation capacity, and all of these options are potentially very expensive. Electricity storage technologies are prohibitively expensive at present and other storage options have been suggested, for example power-to-gas or heat storage. The potential for such technologies to contribute to system management will depend on how the rest of the energy system evolves (e.g. whether we use electric, hydrogen or oil-powered vehicles). We do not have a good understanding at present of how the electricity system investments could be optimised to
276 Murray, K & Bell, KRW (2014). Wind Related Faults on the GB Transmission Network. Proceedings of the 13th International Conference on Probabilistic Methods Applied to Power Systems, Durham, 7-10 July 2014.
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best support the development of a low-carbon energy system, at low cost, while maintaining a resilient supply. This is an issue now because generation and network assets have long lifetimes and investments now are likely to lock-in electricity system infrastructures for decades. This means that it is important to consider the longer-term implications of investments that are made to support the system in the 2020s and 2030s, and in particular how they are likely to affect the evolving UK energy system more widely. We believe that planning horizons for the electricity system need to be much longer in the future than they have needed to be in the past. They should account for the greater uncertainty in demand going forward, for a more inflexible supply and for a greater integration of the electricity system with other parts of the energy system. Question 9. Is the technology for achieving this market ready? How are further developments in science and technology expected to help reduce the cost of maintaining resilience, whilst addressing greenhouse gas emissions? Are there any game changing technologies which could have a revolutionary impact on electricity infrastructure and its resilience? The main network technologies that are seeing steady improvement in capacity and control capability are in HVDC. Cheaper superconductors would promise significant benefits. On the demand side, the estimated potential for efficiency improvement of ~100TWh/year is with existing technology. Future technical change is likely to increase this potential. Demand-side response promises to be significant. As yet, the incentives to DSM seem not to be strong enough and, for many users, the enabling infrastructure is not present. However, the roll out of smart grids will address the latter and incentives will rise if and when system balancing problems become more acute. Energy storage is potential game-changing, in terms of enabling the use of high levels of variable renewables without large scale back-up generation capacity. However, at present, electrical energy storage remains too expensive relative to the main alternative of higher network capacity to share surpluses or deficits with other areas except where network options are particularly expensive, e.g. in connecting islands. If the cost of storage comes down, storage bought for other reasons can be exploited, e.g. electric vehicle (EV) batteries, or the difficulty of increasing network capacity goes up, e.g. because of increasing difficulty in gaining approvals for overhead lines such that much more expensive undergrounding options are required or even that the environmental impacts of undergrounding are deemed unacceptable, then the situation changes. However, a scenario in which the total cost of reliability becomes lower than at present is not impossible but unlikely. In respect of storage, currently the cheapest form is storage of heat. When space, water or process heating uses electricity, heat storage capacity allows some scheduling/time-shifting of electricity demand and this can help to smooth out surpluses or deficits of power even though, depending on the nature of the storage, at some cost in terms of efficiency. In general, storage of heat in low cost devices (e.g. water tanks and storage radiators) and buildings themselves is already cost effective for diurnal and other short term fluctuations. However, inter-seasonal heat storage remains costly and therefore would needs further
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development to become a solution to the problem of electrifying heating. This highlights a key issue for the period out to 2030: how will demand for heat be met, and how do the different energy systems – electricity, gas and heat – interact? One alternative vector often discussed for moving energy from one place to another also promises easier storage than electricity. This is hydrogen, though whether the cost trajectory and the infrastructure investment associated are such that it represents a realistic option in the next 15 years is a subject of some discussion. Question 10. Is UK industry in a position to lead in any, or all, technology areas, driving economic growth? Should the UK favour particular technology approaches to maintaining a resilient low carbon energy system? - Question 11. Are effective measures in place to enable Government and industry to learn from the outputs of current research and development and demonstration projects? - Question 12. Is the current regulatory and policy context in the UK enabling? Will a market-led approach be sufficient to deliver resilience or is greater coordination required and what form would this take? - 19 September 2014
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UK Energy Research Centre (UKERC), Professor David Newbery, Cambridge University and Professor Michael Grubb, University College London – Oral evidence (QQ 69-79)
Evidence Session 6 Heard in Public Questions 69 - 79
TUESDAY 4 NOVEMBER 2014
Members present
Earl of Selborne (Chairman) Lord Broers (co-opted) Lord Dixon-Smith Baroness Hilton of Eggardon Baroness Manningham-Buller Lord O’Neill of Clackmannan Lord Patel Lord Peston Viscount Ridley Lord Rees of Ludlow Lord Willis of Knaresborough Lord Winston ________________
Examination of Witnesses
Professor Keith Bell, Scottish Power Professor of Smart Grids, University of Strathclyde, representing the UK Energy Research Centre (UKERC), Professor David Newbery, Director of the Energy Policy Research Group (EPRG), Cambridge University, Research Fellow at Imperial College London, and a Member of the Panel of Technical Experts for DECC on National Grid’s Electricity Capacity Report, and Professor Michael Grubb, Professor of International Energy and Climate Policy, University College London
Q69 The Chairman: Welcome to our three witnesses. Thank you for joining us. If you would like, first of all, to introduce yourself for the record. We are being broadcast and we are on web camera, so it would be helpful for the record to have your names. If any of you would like to make an introductory statement do feel free to do so.
Professor Bell: I am trying to work out which end we start from. I am Professor Keith Bell. I am from the University of Strathclyde. My title there is the Scottish Power Professor of Smart Grids. Although my chair is sponsored by Scottish Power I have the privilege of working with many different companies in the electricity sector. Also I have done work with the Scottish Government, the Government of the Republic of Ireland, with companies across
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Europe. I describe myself as an independent researcher and I am here today representing the UK Energy Research Centre, which is, we could say, the Research Councils’ flagship energy research initiative. Its particular attraction, as far as I am concerned, is its multi-disciplinary nature and the way it succeeds in bringing together social scientists, economists and engineers.
Professor Newbery: I am Professor David Newbery. I am the Research Director of the Cambridge Energy Policy Research Group. I am also a part-time Research Fellow at Imperial College. I am a Member of the Panel of Technical Experts on National Grid’s Electricity Capacity Market Report, and I also sit on the Ofgem Low Carbon Networks Fund and Network Innovation Competition panels.
The Chairman: Professor Grubb?
Professor Grubb: Michael Grubb. I am Professor of International Energy and Climate Change Policy at UCL. I am also senior adviser to Ofgem but obviously here speaking in my academic capacity and cannot speak on behalf of Ofgem. I have an opening comment if you wish.
The Chairman: Yes, please.
Professor Grubb: It is perhaps a broad and general observation that if I look at the press coverage over recent weeks of National Grid, it does feel slightly like a dilemma for this Committee. It feels a bit like holding a trial when the press has already decided the defendant is guilty. One of the things that may complicate the task of this Committee in sorting out the evidence and realities is the terminological confusion in certain areas and the baggage, which I think reinforces the idea that we have an electricity system like a cliff that somehow has enough generation to meet demand or not, and then the entire thing falls over a cliff. In that sense, the terminologies of supply margin are not helpful and the terminology of loss of load expectation is fundamentally misleading because it has nothing to do with the expectation that anybody actually is involuntarily disconnected.
Neither of those helps us understand the reality, which is trying to deal with a system in which we are evolving many more options and much more flexibility. The real challenge around resilience is understanding that and how robust are those systems.
Q70 Lord Broers: Your opening in respect of this first question: we have heard that the capacity margin will be squeezed over the next two winters. How is this expected to affect the resilience of the electricity system? Will the system be able to cope if there are any more unexpected events, like the recent ones? Are the New Balancing Services that are being implemented by National Grid likely to be required to balance supply and demand on the short term? Have these been tested and are they reliable? Finally, what role do you think industrial backup generation could play in balancing the system if required?
Professor Newbery: I am happy to start off, and I am sure Professor Bell will have other things to add. The first point to make is, of course, unexpected events could cause blackouts, because if you had a system that was so resilient that it never under any circumstances had a blackout you would clearly be spending far too much money. The question really is: is the risk acceptable? I would suggest that it is in the short run. We probably face a tighter situation than we will in 2018/19 when we secure capacity. Perhaps later we can come back to our view on the Panel of Technical Experts that we have arguably prematurely secured too much capacity for that later period, but in the short run the New Balancing Services that have been procured will be tested.
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I am reassured by the statements that have been made to this Committee from generators that more plant will be returned to service. As Professor Grubb has already said, the idea that when the system is tight you instantly lose load is mistaken and there are a whole sequence of actions that can be taken. The one that seems to have been seriously neglected is the ability to import over the interconnectors. The panel strongly criticised National Grid for assuming that they would make no net contribution, which was odd given that both DECC and Ofgem had commissioned reports sometime before, trying to estimate the contribution that the interconnectors would make to security of supply, and suggested that they could make at least half of their nominal capacity available. It is also particularly odd—now that DECC has consulted on the ability to secure capacity over the interconnectors—that no space was made for that in the upcoming auction.
We think that understandably perhaps politicians, and particularly Ministers, are so nervous about the concept of the lights going out—and in particular the Daily Mail-type views that that might happen—that they are overcautious, and that has high costs that we can elaborate on.
The Chairman: Did Professor Bell want to add anything at that stage?
Professor Bell: Yes, I would add that I have some sympathy with the notion that we might be over-procuring through the capacity market and I would agree with what Professor Grubb said at the beginning, that we should be clear about what the metrics are and on what basis those metrics are being developed. As Professor Newbery has said, the metric that has been proposed and is implemented in the Capacity Mechanism makes a certain assumption about the availability of power over the interconnector.
You can make a different assumption and then you could adjust the metrics, so that whatever you assume you should have your choice of the standard that understands what the assumptions are that are being made. It certainly has been the case in the past that you can procure system operator to system operator services—as they are sometimes known—over the interconnector to support the meeting of demand. We could get into the technicalities of the way the assessment is done but I would agree, certainly, that we need clarity on what the reference standard means.
In terms of whether we face some risk of loss of supply, as has been said already, there are circumstances under which the lights can go out across a very large area very quickly. Fortunately, they are very rare. We have seen them in other countries. So far we have not seen them to a large extent in Britain, but the risks are there. That is just one example of the fact that the causes of loss of supply are many and various. I think in a previous session there was some discussion about individual Members of the Committee who have had their electricity disconnected. Most people’s experience of disconnection is to do with an event that originates on the distribution network and is nothing to do with the availability of generation on the system as a whole.
When you get to the layer of simple availability of generation to meet demand you are quite down the tail of the distribution of individual disconnection events that people experience. Again, as has already been said—and this comes back to the point about the metric—it is important to be clear that there are three hours per winter that represent, as I understand it, not the physical disconnection or the probability or some kind of indication of the probability of the disconnection of demand but rather the need for the system operator to start taking actions. The first one is this maxgen thing that was talked about in the earlier
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session; the next one would be, yes, emergency actions on interconnectors; and a further one would be voltage reduction. It would be rather useful to see analysis that articulated precisely—or as far as you can, given the uncertainties in the available data—the disconnection chance. Given all that, I would share Professor Newbery’s views that we are not facing a crisis.
Q71 Lord Broers: Professor Dieter Helm told us that the costs would be lower if we had a larger margin. As an economist, Professor Newbery, do you agree with that?
Professor Newbery: Yes. This is one of the points we tried to stress in our Panel of Technical Experts’ reports, that if you over-procure capacity then the nominal cost is about £2.5 billion but the net cost to consumers is less than that because the prices will be lower. A larger capacity margin means lower prices in the wholesale market. But that has consequential effects. Two of them are that the cost of supporting renewables goes up because the difference between the wholesale price and the strike price increases.
If that goes up then the Levy Control Framework restricts the amount of renewables you can put on the system, so there are adverse consequences for one of the main targets of the electricity market reform. If we lower the price in this country relative to other countries the economics of building interconnectors is undermined somewhat and, since renewable generation is imperfectly correlated the wider the area over which you trade, that disadvantages the penetration of renewable generation. It is true that the prices may come down but it would be unwise to ignore the adverse consequences of that.
Viscount Ridley: To follow up on Lord Broers’ point, I think we probably accept that if it looks dangerous that the lights are going to go—it is a very cold winter and there is a lot of capacity offline and so on—there are all sorts of things that can be done to help it out, but is it not a price spike at that point that is the thing that consumers will most feel? That will be just as big a political crisis for politicians if there is a huge spike in energy prices because of a crisis of that kind.
Professor Newbery: Let us be quite clear, domestic consumers do not face half-hourly wholesale price spikes. They get, effectively, smoothed average prices.
Viscount Ridley: They get fed on eventually, do they not?
Professor Newbery: Then the question is: what is the average price over the course of the year and in how many half hours does the price reach that level? Let me give you an example. In 2012 a cold winter in France had the wholesale price hitting the price cap of €3,000 a megawatt hour for many hours. But the domestic consumers in France, by and large, enjoy rather low prices because the rest of the time the prices are pretty low. In the industrial and commercial market you have the choice, you can choose to buy spot—most people contract—and the contract will hedge you against that sharp spike. But the sharp spikes are extremely important for motivating short-term responses to improve the resilience of the system. One of the adverse things you could do is to suppress those short-term price signals.
Q72 Lord Peston: Yes, can we go on to an explanation of the capacity market? I freely confess the harder I try the less I understand how, first, it actually works, and secondly, how it is meant to work. But am I right that this is a payment system that is meant to get the optimum amount of capacity available and that is its ultimate objective? Am I right on that?
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Professor Newbery: Yes. You start with the security standard, which, if you properly interpret it, would lead you—given the kinds of generation and interconnection on the system and the responsiveness of the demand side—to determine how much you need to meet that security standard and then you—
Lord Peston: Yes. Just to interrupt you at that point, that standard would be a standard of the probability of running out, is that right?
Professor Newbery: Taking a very large run of years—
Lord Peston: Yes, but it is a probable—
Professor Newbery: Yes, and, again—as has been repeatedly stressed—you have to be quite clear what “running out” means. It is not this knife edge; it is the manner to which you move into a number of other—
Lord Peston: Dangerous situations essentially or difficult situations.
Professor Newbery: When you have run out of all of the ability of the system operator to manage the system, including controlled disconnections of people who are willing for a lower normal price to bear the risk that they will be occasionally disconnected but that is going very far down the list of actions. But perhaps Professor Grubb will know more about these actions that can be taken.
Professor Grubb: Perhaps I could pick up a couple of those points but the first is to stress that the measure the Government uses in determining security standard to then inform the Capacity Mechanism is a value of loss load, which is about 100 times the typical price of electricity. In that sense, it is a pretty high measure and the question that I think all of us are interested in is about the whole range of things that can kick in between the normal long or average wholesale price and something that is more than 100 times as high, and there are a lot of things that can come in.
To stress in relation to the first and last of Lord Broers opening questions, maybe I will give a brief illustration around “Will the system be able to cope and how worrying is the supply margin?” In what other sectors do we have this language?” For example, what is the supply margin in food? I had a look and last year the UK produced 60% of its food consumption. Obviously we can produce more but let us say we have a supply margin of minus 30% in food. None of us starved last year. Of course, that is not a perfect analogy. We are more interconnected—more trade routes, more storage capacity—but, nevertheless, we can say, “Be careful about this idea there is a supply margin and once it is too small all hell breaks loose”. No, there are lots of other things that then happen, like prices rise a bit and attract more imports and so forth.
In terms of the economics of this in relation to your specific question regarding Dieter’s remarks that we should rely much more on the capacity market, I was a little surprised if that is a recommendation that we rely far more on Government procurement than on market-based signals of any potential scarcity, given that—as David said—the impacts on consumers are anyway smoothed out at the retail end. It is about the relative economics of those occasional price spikes driving the responses of generators and others on the system, vis-à-vis the economics of a wholesale subsidy or a wholesale payment to enduring capacity.
To finalise that point in a sense, the last question in this opening list was: what role do you think industrial backup capacity could play?” I suspect the answer is: very considerable. I did
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have a look. There appear to be no firm published statistics on this, but the evidence I have is the amount of industrial backup capacity is somewhere probably between 10% and 40% of total peak demand on the system. That is not generally included in this indicator of the supply margin. In other words, the amount of existing capacity of plant, which is either industrial backup or in some cases retired—mothballed, potentially awaiting use—is much greater than any discussion about the supply margin. The combination of Capacity Mechanism and New Balancing Services should—but may not sufficiently in current designs—bring some of that reservoir of resilience into the electricity system, which is not adequately done at present.
Q73 Lord Peston: To follow the lead you are giving us, you said we should compare it with other examples. The area that I used to make a decent living from was doing operational research involving inventory control. Following David Newbery’s point again, it was incredibly difficult to persuade firms that the marginal cost of never running out of spare parts was so high that there would be very much more profit to be made if they would run out. That is why, David, I used the expression “running out” rather than the relevant one here. What I am trying to get clarified from you is that the optimum position, and the optimum outcome in the area we are discussing, is not to have available supply at some appropriate rate. Is that the correct view: that the lights should go out occasionally?
Professor Grubb: No, not personally speaking.
Lord Peston: Is that right or wrong? I mean on average, if it is an average proposition.
Professor Newbery: The lights do go out—at least in my part of the world—quite often because the distribution network is overstressed or because the wind has been blowing or a tree has fallen over the local loop. These are not unexpected events. The question is: how much security and confidence do we want at the system level?
Lord Peston: Yes, that is what I am trying to press you on.
Professor Newbery: Obviously, we want to have enough and that is what exactly a security standard aims to set. One can discuss whether or not we have set the right one. All I can observe is the Loss of Load Expectation is similar to most other European countries but it is lower than quite a few. Whether we have interpreted that Loss of Load Expectation correctly is very doubtful and I think we have erred on the side of caution. We have a very secure standard that we have overegged. So in terms of security of supply, at the level of generation adequacy and access to power, I think we are doing well. Whether we have the right resilience elsewhere in the system depends on where you are.
Lord Rees of Ludlow: To follow up that, what are the figures on our relative resilience and number of breakdowns, compared to, say, France or Germany?
Professor Newbery: We have the same loss of load expectation standard as France and Germany. Belgium has two and a half times as high. As far as I can tell, the only event that we have had since 1990 that was exciting was the loss of Long Gannet and—30 seconds later—the loss of Sizewell, which was a massive and very unexpected uncorrelated event happening within a very short period of time and that was managed without much happening.
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The Chairman: To be fair, if we are looking at generation failure or outage rather than distribution, probably it was a three-day week, was it not—which is now 40 years ago—that we lost?
Professor Newbery: Exactly.
Q74 Baroness Hilton of Eggardon: Basically my question has just been asked. On the international comparisons with our generating capacity, do you think we have the same level of security as elsewhere and how would you offset costs against the benefits—we have already been talking about this—of having a secure system?
Professor Grubb: As you say, it has been partly answered. I will just point to a paradox that if, as may be the case, the measured margins are tighter than some of our continental countries that implies there is a high chance that interconnectors will flow in our direction when needed. It is not a simple thing to say, “Oh, look, we are worse off than those”. I am inclined to agree with David; I think that we have standards that err on the conservative side—perhaps quite rightly—and have not taken enough account of the range of options.
But perhaps underlying this is my reaction to the question phrased as “the lights going out”; there are some critical uses of electricity for which the standards should be extremely high. It should be pretty much always the case that we try to make sure enough generation is available to meet those, compared with the risk of transmission and distribution failures, which do dominate forced disconnections. That is a reasonable benchmark to say the generation system should not be the dominant cause of blackouts, compared with distribution. It is not a numerically optimal view; it is a very cautious security-orientated view. But, again, I come to this problem where you get the phrase about lights going out as if all electricity use is of the same value and essential nature.
I may have one example in relation to the industry side of this. I was rather struck a week or two ago to see a CBI spokesman say something along the lines of, “This is terrible. Industry is being offered contracts to sometimes disconnect from the grid or reduce its demand, and this is a terrible thing for British business”. It seemed to me very strange to hear the CBI propositioning that giving a company a new option to make more money than it otherwise would do was going to damage its competitiveness. It seems to me it is a perfectly rational thing to do because over-engineering the system in unnecessary ways ultimately requires all of consumers, including industry, to pay higher prices.
Q75 Lord Rees of Ludlow: I would like to ask about the consequences long-term about a growing dependence on decarbonisation types of energy generation. This is more intermittent, of course, and may need new technologies and also will make a more complicated grid. I wonder if you would like to comment generally on some of these issues.
Professor Bell: Yes, I think it does make operation of the power system more complicated. I tend to start from the perspective that decarbonisation is not just an option, it is an essential thing that we need to do. For me, the challenge is: how do we facilitate it in such a way that we achieve whatever we regard as being a sufficient level of reliability of supply in the cheapest way? There are all sorts of options that are out there. In respect of many of them, exactly how you do it is not yet determined. It is too early to say. There is still more research that is needed. Lots of people have jumped on the smart grid bandwagon and say that smart
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grids are the answer. I am not sure they always know what the question is. As we go on we will articulate that question much more precisely.
In the previous session, Mike Calviou from National Grid articulated some of the issues to do with the variability of renewables—the uncertainty of renewables, although the forecasting of a few hours ahead is not too bad. To get the net balance correct you need to fill in the gap between renewables and net demand. You have to have some kind of ability to schedule and ramp up and ramp down the other generation resources and the ability to withstand faults or failures. Professor Newbery alluded to an event back in 2008 where two large generating units were tripped within a short space of time.
The system is operated now in such a way that you can keep the system frequency within statutory limits for the loss of one very large source of power, the reference for which happens to be the reactor at Sizewell. The amount of reserve and response that you need to carry to do that depends on the inertia of the system. One of the sources of the replacement energy for that lost energy is, of course, the store of kinetic energy. If you have a lot of wind farms or any generation or source of power sitting behind a power electronic interface you do not get the same natural coupling, electromagnetically, with that source of energy. One of the ideas is that, when we talk about reduced inertia of the system, that is what we mean. There is still rotating mass. There is research going on on how you can articulate a controlled response to synthesise the rapid utilisation of any store of energy even if it is not electromagnetically coupled. These things are not fully sorted out, to my understanding, but they offer some promising avenues and the challenge for us engineers is to work out which ones are going to work best and most cost effectively.
Professor Newbery: Perhaps I can add something, I sit on the Single Electricity Market Committee of the island of Ireland, which is planning by 2020 to have 75% non-synchronous generation connected and it does not have very strong links to GB. They are actively investigating what services they need now to define in terms of fast frequency response and various other new services and how best to procure them. So we can admire our cousins to the west and see how they deal with this system and learn from it. Of course, we have the advantage of a much larger inertial mass—to use that phrase—and lower penetration, so we face the problem later than some other people do.
Professor Grubb: Your question, Martin, is a very important one, it is a long-term evolution one. In effect, the more one relies on renewable resources, certainly wind and solar, what we are doing is emphasising the move to a system in which the volume of low-marginal cost generation available will fluctuate much more than previously and the cost will be more geographically varied than used to be the case.
Those together imply a greater value, you would expect, from interconnection under stronger transmission and a broader transmission system and associated governance because of the geographical variation. The temporal variation obviously increases the value of storage or access to other systems or technologies and end-uses that can help to provide storage to the system, of which there are quite a range of varying characteristics and costs. But all of those things become potentially more important the further you try to decarbonise the system.
Lord Rees of Ludlow: I have two more questions. One is: what about the grand role of small-scale off-grid generation?
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Professor Grubb: As I alluded to earlier, we still do not have quite enough information even around the present situation, let alone where it may go. But it is clear that there is a growing capacity of what is generally called embedded generation, broadly below the level of direct connection to the transmission system, and including industrial backup of various sorts that is usually considered a subset of potential embedded generation capacity.277 Ofgem itself issued a licence modification in the summer to try to improve and accelerate the reporting of that kind of data, which has been rather below the radar screen. The implication, again, is a more intelligently managed and intelligently informed system to get the best balance of all those inputs.
Lord Rees of Ludlow: My last question is about the fact that this distribution is getting more complicated, more vulnerable to cyber attacks and all that. Do you have any comments on whether that should lead to a greater need for a margin?
Professor Newbery: Perhaps I can comment and pick up the point that was made in the previous session that Ofgem, through the Low Carbon Networks Fund and the Network Innovation Competitions, is actively looking at how low-carbon generation can be better connected to the distribution networks, especially embedded generation. A lot of that has to be active network management, increased visibility of what is happening on the distribution network, better co-operation and co-ordination between the transmission and the distribution networks. The research results from the first four years of the Low Carbon Networks Fund have been extraordinarily promising. From being probably one of the laggards in Europe in the smartening of the distribution network, we are probably now very much at the cutting edge. At a recent conference some 800 people were present listening to the progress that has been made and what we now know that we did not know four years ago.
The Chairman: Lord Ridley, do you want to follow up that point?
Q76 Viscount Ridley: Yes. I want to press you a little bit further on the intermittency issue. The system is designed to cope with variability of demand. If you add variability of supply to that as well, of an unpredictable nature, it must increase the degree to which you have to call on supplemental balancing, or whatever it might be, which is inevitably going to be in price spikes, which inevitably is going to make the things more expensive. For example, if the wind drops just at the moment when everybody arrives home and turns on the television, that puts more of a strain on the system than if you were not relying on wind power at all.
Professor Newbery: Let me challenge one of your comments that the price spikes make it more expensive. The complaint on the continent of the generating companies is the massive solar and wind installations in Germany have so crashed the prices that they are retiring almost brand new Combined-Cycle Gas Turbines, so that does not follow.
Viscount Ridley: Yes, but that was hugely subsidised, so it did cost the customer somewhere else.
Professor Newbery: It did, big time. But to come back to the question, it depends on what kind of intermittency you have. Wind: as you get closer and closer to real time, the reliability of that improves, compared to a nuclear power station, which could fall over on a blink at 277 Note this is also potentially a source of confusion, because it may then get considered as demand-side response, insofar as it means these entities would run their back-up generation instead of drawing power from the grid.
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any moment—very improbably. But your confidence in the wind supply, as you get to within half an hour and five minutes of dispatch, is very high. Solar, on the other hand, is very tricky because the sun can go behind a cloud. If you have what I would think an unreasonable amount of PV in a rather cloudy part of the world connected to your system, you can stress it. We have discovered that there are rather important design features that you need to incorporate into that. One of the things I think that the Germans are discovering is that having all PV panels disconnect to the certain frequency, the same frequency, is a bad idea. We are learning quite a lot about how to improve the resilience of including these new technologies.
Professor Bell: If I might just concur there, the nature of the risk is different. We have to distinguish between variability and uncertainty, so something can be highly variable but we can have a good forecast of it some time ahead. The probability of losing a certain amount of power within a certain period of time is different, depending on what the resources are. The wind turbines are distributed across the whole country. It does happen that when a storm front comes through you can go from 100% output to near enough to 0% output but it takes a few hours for that to happen. The critical thing then is identifying when it starts, so you can start ramping up the replacement generation. Yes, the 50.2 Hz problem, as it is known in Germany, when the PV panels were being specified and some standards articulated they would look across the system in Europe and say, “How high does the system frequency go? It almost never gets above 50.05, never gets above 50.1. Let us put a safety margin in, 50.2. That will do”. Then in the last few years they found it is creeping up to 50.1 and a bit above and, “We had better go back and retrofit new software in the panels to make sure it does not all disconnect at 50.2”. It is slightly ironic that if you went from a surplus of generation and you did disconnect them all—the lights, a lot of the lights, talking about the lights going out—there would be a serious disturbance in Germany. I heard that it was maybe costing €1 billion to fix that but it is one of these things you learn. As you get experience with this it does not mean that PV in the right places in the right parts of the world is a bad idea; you just have to manage the engineering in the right way.
Viscount Ridley: No, but it does mean that it is added to a resilience problem.
Professor Bell: If you managed it correctly, there is always a resilience problem. As we were talking about it earlier, the system is not 100% reliable and if you were making it 100% reliable you are probably overvaluing your electricity supply. Different people at different times will value it in a different way. It is about making the right judgments about what you do at the right time. On occasions I have given talks on how come the lights go out or, as engineers, we can get very interested in big disturbances. It is very interesting to see the complexities and how they work out. We can learn a lot from them. Another time I changed the title and I said, “How come the lights do not go out more often?” It is a great engineering achievement that we have managed to have the reliable supply that we do at the price that we have electricity.
Professor Newbery: Just to give a little more comfort, the laws of physics work everywhere in the world. One of the things we can do is look to other countries and learn from what problems they have run into before we have to face them. Germany is a very good example.
Q77 Lord Broers: Professor Grubb, you have said a couple of times that your estimate of the potential industrial backup is between 10% and 40%. That is a huge range. Should initiatives be put in place to better determine what that is?
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Professor Grubb: Yes.
Lord Broers: Should this be one of our recommendations?
Professor Grubb: First, they are not my estimates. Simply, the only two points I was able to get anybody to offer any quantified indication were, respectively, 5 gigawatts and 20 gigawatts, but they are big numbers. As I mentioned, Ofgem did issue a licence modification this summer to try to improve the data on that. But, yes, recommending—there appears to be an important resource here that we should understand better—absolutely would make sense.
Maybe just to build on the theme: first, the discussion we just had emphasises that innovation is not just about widgets. It is about understanding the system and how best to utilise all the different kinds of widgets and associated options that may be available, contingent often in part on policy and regulatory design. Some of it may involve creating new kinds of markets to tap into some of these. In some countries you have, more or less, developed markets around reserve requirements and balancing and other stuff. But the essential point is, it is changing the notion of: what do we mean when we talk about the system? It used to be desperately simple. In the ‘good old CEGB’ days, we knew the power system was what the CEGB ran and electricity demand was what we demanded of it. That is not the world that we are in. As an example, in terms of the variability versus uncertainty, I agree. Uncertainty, for a number of the intermittent sources, is not the problem; variability is, depending on the time horizon. One can address that better through a whole mix of issues, some of which we have touched on.
Broadly, anything that either uses fuel, which can be gas or biomass or various other things, or supplies heat to something reasonably well insulated, has capacity to help manage variability on various sorts of timescales. For example, if we do end up in a world of substantial electric vehicles, along with pricing as time-varying signals and other means to help determine when people plug in and when they charge up, that could add significant storage. And if the battery has reached the end of its useful life in the vehicle, instead of throwing it away, should they put it in their garage and connect it to the system and should they then receive a capacity payment and so forth? The world is remarkably wide in terms of options when one starts thinking through these possibilities. As I say, technological innovation is often the relatively minor part of what is required. It is also expanding our own understanding and management of the systems.
Professor Bell: If I could just add something briefly on industrial generation or on-site plant: that is likely to be one of the things that is most prominent in these New Balancing Services that National Grid are procuring. That is where the offers are coming from. If National Grid puts out an invitation to tender for these services that is one of the ways in which you reveal how much of this industrial on-site generation there is. Okay, you want to be sure you can rely on it and, as Mike Calviou said earlier, they will be conducting some tests.
Q78 Viscount Ridley: I want to come to the question of the impact of climate change on resilience and reliability of the electricity system. It is very clear that weather is a big source of non-resilience or potential non-resilience in the electricity system because it blows trees down and knocks out a distribution network or something. The question is: how much percentage does potential climate change add to that weather risk and in some of the written evidence we have seen, I think, you, Professor Bell, talk about there being wetter
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summers and colder winters, but is it just as plausible we are going to see drier summers and milder winters as a result of climate change? I have seen projections that say that, and where you talk about more snowfall, more ice storms and so on but ice storms are a very rare event. What percentage probability are you adding to the weather problem from climate change?
Professor Bell: I was very careful in my written evidence not to make any claims about the climate science, since I am not a climate scientist, so I would not dare to say whether it is more likely to be drier summers or wetter summers. What we can do—and I can try to help with, as an engineer, and my colleagues I work with—is to understand if the climate means these kinds of weather effects, what that would mean for the power system. We can at least be forewarned at such time as the climate scientists are able to give us some better projections on the weather impacts—and the IPCC’s Syntheses Report that came out on the weekend was starting to make some stronger statements about likely weather impacts and beyond just changes of average temperature. Then we can have an idea of what that might mean.
You are absolutely right that weather is one of the major influences on loss of supply now.
Coming back to something we talked about earlier, there are different mechanisms by which one’s supply might be lost and I tend to think there is a bit of a psychological thing that goes on here as well to do with the impact—how we perceive the impact. I am looking forward to working with some of my social science colleagues in UKERC on this who can help me understand it a bit better.
But the experience of having the lights in your street go out for an hour or however long you think it was—when you happened to be out of the house at the time and you come back in you need to reset all the clocks—is an annoyance but it is not a big thing. You could compare that with if you are depending on electricity for your heating and you lose that heating for 12 to 24 hours. That is serious. If the whole country is blacked out, which does happen—it has not happened in Britain but it happens in places—it is a very high-impact/very low-probability event and we maybe respond to that in different ways. I expect your Committee would be desperate to know what on earth was going on if we did black out the whole of Britain. It can happen, unfortunately.
The mechanisms—we can look around the rest of the world, as Professor Newbery was saying and try to learn from these—are complex but there are often some common features about individual items of control plant that did not behave in the way they were supposed to. Maybe there was some natural event that triggered it; it might have been a lightning strike or some high winds and things cascaded in a way that was not intended but was just a phenomenon of a very large complex system.
If we got changed weather patterns then the individual kind of single events that the system is designed to withstand would happen more often, but you would not notice an impact because the system is designed to withstand a single lightning strike or a single double-circuit overhead line coming out of service because of the high winds and there is a short circuit. That is okay. But if the weather events become so severe that you see multiples of these events occurring simultaneously, then you start to impact on reliability of supply and then you run into some of these complex situations of cascades and the system running away—a widespread disconnection, not just a local disconnection. We should not
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underestimate the impacts of local disconnection. The previous session talked about the ability of the distribution networks, in particular to restore supply.
Clearly, there were lessons to be learned from what happened last winter. If I understand it the regulator has been quite firm with some of DNOs in particular that they judged underperformed, and one looks forward to improved performance. One of the things that will improve that is the information that is available to the DNOs. I know that software providers are working on devices where individual consumers can take a picture on their mobile phone and from there the DNOs can understand where the picture was taken and can see from the picture what the nature of the outage is. They can then line up the right resource with the right equipment to get to the right place to restore supply as quickly as possible.
Q79 Viscount Ridley: I suppose my point is that all of that is already a good idea for dealing with weather. Do we need anything extra for dealing with climate change? What I am concerned about is that we might end up over-procuring resilience to climate change, just as we are over-procuring Capacity Mechanisms. For example, if we say that winds are going to get 10% stronger in 100 years, does that mean we have to replace the whole high-voltage transmission network because it was only designed for a certain wind speed or something like that?
Professor Bell: That is a good example of something that might need to happen but it does not all happen overnight; it cannot happen overnight. You are replacing a system that you need to use, so you have to take bits of it out of service to replace it, so it has to be planned over a period of time. We are talking about something that is probabilistic, so the probability of a certain wind speed exceeding what apparently is the safe limit—how often is that going to occur? Over how big an area are you going to experience it?
For example, in 1999 in December—I do not know whether the French Michael Fish saw it coming or not—but there were severe storms that affected north-west France and a number of transmission towers were physically damaged. It was not just a temporary outage; there was a lot of work to repair the towers and that took some weeks to get the system back up and running. What you can do in the meantime if you think the risk of that is increased is adopt some policies on spares, temporary towers that you can transport and erect relatively quickly. As old towers need to be replaced with new ones because they have reached their end of life—the metalwork needs to be replaced or the foundations—at that point you can use a new specification to be able to withstand higher wind speeds.
Again, a bit like what we were saying earlier, it is not an all or nothing, there are ways of managing it and managing the transition. But, yes, one of the things we need to be looking at is, what is the likelihood of seeing more outages due to high winds? In what way are those outages caused? What proportion of them lead to permanent damage to the towers and then making a judgment about whether new towers, as they replace old ones, need to be designed to a higher standard?
Viscount Ridley: How much we should be prepared to spend.
Professor Bell: Yes, absolutely, how much we should be prepared to spend, yes.
The Chairman: That probably brings us to a conclusion because it is 12.30 pm; we try to end by then. Thank you to Professor Grubb, Professor Newbery and Professor Bell for a very informative session. You have a great deal of expertise and we have benefited enormously
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from it. We will be sending a transcript for minor corrections, so we have the record correct. Thank you once more for the help you have given us.
UK Hydrogen and Fuel Cell Association – Written evidence (REI0023)
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UK Hydrogen and Fuel Cell Association – Written evidence (REI0023) The House of Lords Science and Technology Select Committee are looking in the context of the energy trilemma of energy security, affordability and decarbonisation at the current and future contribution of science and technology to ensuring the resilience of the UK’s electricity infrastructure. As well as providing resilience the infrastructure will need to deliver low carbon electricity at affordable prices noting that the Committee on Climate Change recommends that the carbon intensity of power generation should be reduced from 500g CO2/kWh to 50g CO2/kWh by 2030. They seek information on options which can provide additional low carbon generation capacity at peak times or smooth out peaks of demand. Introduction 1. This response to the Call for Evidence is submitted by the UK Hydrogen and Fuel Cell Association. The UK Hydrogen and Fuel Cell Association (UK HFCA) works to ensure that fuel cell and hydrogen energy can realise the many benefits offered across economic growth, energy security, carbon reduction and beyond. Through the breadth, expertise and diversity of our membership, we work to trigger the policy changes required for the UK to fully realise the opportunities offered by these clean energy solutions and associated elements of the supply chain. 2. Fuel cells and hydrogen are ‘game changing’ technologies providing low-carbon solutions across transport, stationary power and beyond. The growing industry is bringing benefits across the UK: creating new jobs, supporting UK economic growth and improved competitiveness in energy markets globally. General Remarks 3. Commercial fuel cells powered by natural gas or hydrogen are available now, and hydrogen capacity matches current demand. The scale of these options to address the resilience of electricity infrastructure is at relatively small scale on the DNO level. Therefore, we will focus on medium term (2030) opportunities and point back to the activities in the short term that will enable medium term outcomes. 4. We support the thrust of the Committee’s questions testing the uncertainties in the impact of the various external threats and policy interventions in the electricity system. 5. We are rely on whole system model conclusions by others, but the feedback we get from talking about such dynamic stochastic general equilibrium models (e.g. Markel, ESME, TIME) is the difficulty they face in representing local system changes, and the diverse and multiple drivers for the introduction of new technology at particular sites. While better spatial modelling has been sought - in, for example, the case of CHP models (such as district heating in SEDSO278) - including the impact of market making policies and real but small scale
278 Li, FGN; (2013) Spatially explicit techno-economic optimisation modelling of UK heating futures.(UCL).
