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APVA Submission to the IPART Energy Issues Paper on SolarFeed-in Tariffs, August 2011

September 2011

The NSW Independent Pricing and Regulatory Tribunal (IPART) has released an Energy Issues Paperon Solar Feed-in Tariffs, with a view to ‘setting a fair and reasonable value for electricity generated bysmall-scale solar PV units in NSW’.

The terms of reference the NSW Government has set for the IPART review are to recommend:

a ‘fair and reasonable value’ for the electricity generated by small-scale solar PV units andexported to the grid, which is consistent with the Council of Australian Government (COAG)principles for feed-in tariffs

how this value should be implemented in NSW – for example, whether it should be used to seta minimum feed-in tariff that all retailers must pay for the solar generated electricity theircustomers export to the grid, or a benchmark price that retailers and customers can use as aguide in negotiating a price for this electricity; and

whether comprehensive network system modelling is required to value the impact of small-scale solar PV on network costs.

Summary of APVA comments

The APVA recommends that photovoltaic (PV) electricity fed into the distribution network in NSWbe valued at the same rate as the prevailing retail tariff (ie. net metering). This is considered to reflectthe competitive market price for electricity at the point of end use, and thus provide a fair andreasonable value to NSW residents and businesses which have chosen to invest in their own PVsystems. In the short term it will require changes to the treatment of DUOS and possibly RETobligations for retailers so as not to impose an undue cost on them, as discussed below. Privateinvestment in PV reduces the investment needed to otherwise provide this electricity, and providesadded benefits, including reduced electricity costs for all consumers.1

A 1:1 arrangement is the most straightforward option to apply, with the lowest transaction costsfor retailers and customers. It is suitable for:

both net and gross metered systems, and will avoid the need for additional expenditure onmetering

both regulated, flat and time-of use tariffs

both residential and commercial customers.

1Note that here we refer specifically to unsubsidised private investment in DG under net metering, not, for example, PV

installed under the Solar Bonus Scheme feed-in tariffs.

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This arrangement should apply until such time as a separate market for Distributed Generation isimplemented in the NEM. The current market arrangements are now 20 years old and do not provideappropriate price signals for electricity connected to the distribution network. The cost of PVgenerated electricity is now close to the prevailing retail tariff for many NSW customers, whencalculated over the expected system life of 25 years, but other DG technologies will increasinglybecome attractive for customers. These include cogeneration, electric vehicles, fuel cells and variousstorage technologies. These modular, rapidly deployed and low emissions technologies have thepotential to reduce costs and increase reliability of future electricity supply for NSW customers in anenvironment of approaching generation capacity constraints, network constraints and futureenvironment policy uncertainties. However, they also have the potential to significantly reduceelectricity sales by retailers, putting increasing pressure on their traditional revenue and businessmodels. Energy efficiency technologies, including solar water heaters, are already reducing electricityuse and have significant potential for much greater reductions, and so will also have the same sort ofimpact on retailers. As a result, this review has implications far beyond PV.

APVA comments on the Key Issues raised

IPART has identified 25 key issues on which it seeks public comment. The APVA has providedcomments on each issue below, but would first like to discuss the key issue facing PV in NSW and in therest of Australia at present, as previous support measures contract. The issue central to providing anappropriate regulatory framework and associated price signals for PV and other distributed energysolutions into the long term is the establishment of a market within the NEM for Distributed Generation(DG), Demand Management and Energy Efficiency.

Distributed Energy Market

PV may be the first distributed energy solution to have reached grid parity compared to residentialretail tariffs, but other technologies will increasingly become attractive for customers. In addition toPV, those DG technologies that are likely to feed electricity back into the grid include cogeneration,electric vehicles, fuel cells and various storage technologies. These modular, rapidly deployed and lowemissions technologies have the potential to reduce costs and increase reliability of future electricitysupply for NSW customers in an environment of approaching generation capacity constraints, networkconstraints and future environment policy uncertainties. As a result, this review has implications farbeyond PV, especially given the projected levels of deployment of electric vehicles with the capacity toexport electricity to the grid. There is a need for a revised regulatory approach to deal with a range ofperceived and real issues that should be addressed in order to maximise the deployment and benefit ofthese technologies.

Uniform approaches to connection requirements, metering and tariffs across technologies, and alsoacross State jurisdictions would provide certainty, reduce transaction costs (for both utilities andgovernment) and enable the development of capability in DG and associated smart grid technologiesand energy management. Foreshadowing the regulatory approach likely to be taken over the comingdecade will be extremely useful for the steady development of all DG technologies and markets.

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Development of the PV sector in Australia has suffered from stop-start policies and lack of long-termmarket and regulatory certainty.

Such a regulatory framework would include an appropriate value for electricity exported by DG,based on a detailed understanding of its value to specific stakeholders such as network operators andelectricity retailers, as well as to society in general. Development of such an understanding will takesome years as the network and wholesale market impacts of distributed generation such as PV andelectric vehicles are determined – especially as penetration levels increase over time. In the interim,there is a need to maintain the PV industry and avoid placing unreasonable barriers in the way of newlydeveloping industries such as electric vehicles. The simplest way to do this in the short term is toremove the DUOS and RET charges on PV electricity (for reasons as discussed below), and then set netmetering, with the same price for electricity exported and imported, as the default option.

This would transition PV through to the point when it is cheaper than retail tariffs, at which time anappropriate DG market should be in place. This market would require a regulatory environment thatincludes:

- incentives to provide power at times of peak demand and at locations facing networkconstraints

- incentives for energy efficiency- incentives for demand management at times of peak demand and at locations facing network

constraints- power quality requirements- payments for ancillary services from DG, including maintenance of voltage, frequency, network

loading and system re-start processes.

Wider benefits of distributed PV

Other benefits which may be provided by increased deployment of PV on the distribution networkinclude (SKM/MMA, 2011):

Diversification of energy resources to enhance energy security, principally through diversification in

fuel, technology type and geographic spread of generation. For example, failure of one distributed

generator will have minimal impact on supply reliability.

Widespread adoption of small scale distributed technologies could limit the market power in the

wholesale market.

Improved power quality and reliability in areas where load growth is rapid and network capacity

may become severely constrained during extreme peak periods.

According to a CSIRO report, an increase in distributed generation would lead to less variable spot

prices. In particular, there would be fewer occurrences of very high prices, which may mean that

some new peaking plant capacity could be delayed.”

As well as:

Reduced risk due to a fixed price, which is known at the time of installation

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Capacity /demand benefits

Other pollutants and environmental benefits not covered by the RET – e.g. NOx,SOx and others,seeTable 1

Reduced land use, with most installations likely to be on buildings or other structures

Reduced water use compared to coal fired generation

Tax benefits to the Commonwealth and State governments

Reduced diesel imports for PV systems deployed in diesel grids or off-grid

Reduced fuel transport

Regional development

Employment across a range of skills

Energy self reliance on a local level

Energy diversification and associated system resilience and security of supply. For distributed PVthis includes reduced intermittent generation impacts, since generators are spread across a widegeographical area and hence less likely to all be impacted at the same time by passing clouds.

Increased building values

Advantages of dual function, with PV having the potential to improve building energy efficiency andto use more natural light

Reduced building facilities/HVAC

Increased rental value

Modularity and speed of deployment, which makes it easier to match load with generation andreduces the need for large capital expenditure many years before the demand requires it.

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Table 1: Wider benefits of renewable energy2

The following questions posed by IPART reinforce the current market rules, which in many cases areinappropriate for DG.

Estimating the financial gain to the retailer

1 What are the direct financial gains to retailers as a result of their solar PV customersexporting electricity to the grid?

Firstly, it appears that Box 3.1 in the Issues Paper is not entirely correct.3 This box aims to set outthe cost components in the retail price of electricity, and thereby states that PV electricity enables theretailer to avoid only 30% of the retail price. However, it appears to have confused some of the fixedand variable components of retailers’ costs. Our understanding is that tariffs can be divided into retail(R) and network (N) components, each of which in turn has fixed and variable components as shownbelow.

R component (set by IPART):

- Fixed ($/customer): is due to the ‘Retail cost allowance’, which covers retailer operating costs,customer acquisition and retention costs, and an adjustment for double counting

- Variable: (c/kWh) consists of wholesale energy costs (which includes costs such as NEM fees,losses, hedging etc), as well as liabilities under various schemes such as the Renewable EnergyTarget, GGAS, ESS etc.

2External Costs, Research results on socio-environmental damages due to electricity and transport, European Commission

Directorate-General for Research Information and Communication Unit3

Also note that Box 3.2 appears to be incorrect because with net metering, the system owner would be paid the retailtariff on all exported electricity. If they are not, then it is not net metering.

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N component (set by the AER):

- Fixed network charges ($/customer) – payable to the network operators to cover fixed networkcosts

- Variable network charges (c/kWh) – consists of TUOS, DUOS, and possibly other obligations setby the government of the time

- Potentially other charges such as maximum demand/capacity charge.

All the fixed components, including the fixed network charges, can be bundled together and passedon to the customer as their Service Availability Charge ($/day) – and so are covered by that charge. Allthe variable components can be bundled together and passed on to the customer as their ‘usagecharge’ (c/kWh). The retailer’s margin is set as a percentage of the N and R components.

Thus, whereas IPART’s Issues Paper states that retailers’ network costs are based on the totalelectricity the retailer supplies to customers, the fixed network charges are in fact recovered throughthe service availability charge. The Issues Paper has also included the fixed retail costs in the Box 3.1pie chart as costs that retailers need to be compensated for as they are not avoided with PV electricity,when in fact they are already compensated for this through the service availability charge. This meansthat the costs that retailers avoid through PV electricity are in fact greater than 30%. As outlined in theIssues Paper, only the ‘green scheme’ obligations and DUOS charges are not avoided with PV electricity.

Thus, the value of PV electricity to a retailer is simply equal to the retail tariff at which it is on-soldminus any costs associated with that sale (eg. DUOS) as well as any costs associated with the purchaseof that electricity (eg. green scheme’ obligations). ‘Bottom up’ approaches such as those that attemptto value PV electricity based wholly or in part on wholesale electricity costs are not only likely to be lessaccurate, they are unnecessary.

It is arguable that a retailer should not have to pay the full DUOS charge on PV electricity that isused either by the system owner (often the majority of the electricity produced under a gross meteringarrangement) or by their neighbours in close proximity (usually the remainder of the electricityproduced under a gross metering arrangement and all the electricity exported under a net metering4

arrangement). This is because (i) the customer already pays the fixed network charges incorporatedinto the Service Availability Charge, and (ii) the amount of the distribution network used for suchelectricity is extremely small compared to the amount used by electricity transported from thetransmission network to the connection point. As such, the simplest, and most likely least costlyapproach (ie. reduced administration costs), is simply to change the relevant regulations so that the PVelectricity is subtracted from the amount used to determine the retailer’s DUOS obligation.

As discussed below, it appears likely, though not certain, that retailers pay for the cost of complyingwith the RET on electricity exported by PV customers - although it appears there is some leeway in howthe rules are interpreted by liable entities and therefore some uncertainty about whether the RETcomponent is paid on all PV electricity.

Minimisation or avoidance of DUOS and ‘green scheme’ charges would mean that retailers couldpay the retail tariff on all exported electricity and their only loss would be on their profit margin(remembering that their customer acquisition and retention costs are already covered by the Service

4Net metering means that the PV system owner is effectively paid at the relevant retail tariff (ie. the tariff the customer is

charged for electricity use at that time) for all generation, whether it is consumed on-site or exported.

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Availability Charge). Note that the retailer also ‘loses’ the profit margin for PV electricity that is usedon-site, as well as any energy efficiency measure that reduces electricity sales – and there have been noclaims by retailers for compensation in these regards. If the tariff paid for PV electricity is reduced inorder to create a profit margin for the retailer, it is likely that this margin would quickly be eroded dueto the transaction costs associated with any system other than net metering.

2 Do retailers pay for the cost of complying with the RET on electricity exported by solar PVcustomers?

Under the Renewable Energy (Electricity) Act 2000, purchases of electricity by retailers (liableentities) from customers that own small domestic PV systems are considered to be acquisitions from ‘aperson who did not acquire it from another person’, and are therefore relevant acquisitions whencalculating liability under the RET scheme (both LRET and SRES components). However, there is someuncertainty with respect to exactly what different retailers are actually reporting and currently paying.Liable entities are required to report acquisitions from small domestic generation systems such as PVsystems, based on the amount of electricity exported to the distribution system. There may be somevariation in the way in which retailers interpret the NEM rules and report accordingly, and what isreported is dependent on what data are available (what metering is installed). It is possible that theelectricity generated by small domestic PV systems may be counted 0-2 times for the purposes ofcalculating liability5. ORER has advised that the liable entities are responsible for interpreting the rulesand so only they really know what approach they take. Thus, we advise that IPART seek clarificationfrom the liable entities.

3 Are there other indirect financial gains to retailers as a result of their solar PV customersexporting electricity to the grid? If so, how can these be estimated? Should these indirectfinancial gains be fully reflected in the feed-in tariff or shared with all electricity customers?

The example of an indirect financial gain given in Section 3.2.2 of the Issues Paper, where theretailer has reduced need to buy electricity on the wholesale market at times of high spot prices, seemsto the APVA to be a direct financial gain, not an indirect financial gain. The following identifies what theAPVA believes to be indirect financial gains.

Electricity produced by DG reduces the amount of electricity that needs to be purchased throughthe wholesale spot market (no matter what time of day it is produced). This moves the clearing pricedown the dispatch order, thereby reducing the average spot price. As the levels of DG increase, thiseffect will become more noticeable. A similar effect is already occurring where wind farms bid in at, orclose to, zero, and so reduce the average spot price.6 This is a benefit that currently accrues toelectricity retailers, and may not be passed on to customers because IPART’s Price Determinations use

5Personal communication from ORER

6Cutler, N.J., Boerema, N., MacGill, I.F. and Outhred, H.R. (2011) ‘High penetration wind generation impacts on spot

prices in the Australian national electricity market’, Energy Policy (in press).

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the higher of the Long Run Marginal Cost (for a theoretical least-cost mix of generating plant) or theaverage spot price.

Electricity produced by DG reduces the amount of electricity that needs to be transmitted throughthe transmission and distribution networks. The percentage of electricity lost in these networksdecreases as less electricity is transmitted. This is reflected in lower loss factors. This is a benefit thataccrues to retailers, and is possibly passed on to customers.

Ideally, any benefit that results from a private investment in any electricity generator should bepassed to the investor. With true cost-reflective pricing, gains to either the retailer or the DNSP shouldaccrue to the DG system owner – which in turn would lead to optimal behaviour of customers andgenerators. This should include the internalisation of externalities.

The calculation of these various indirect benefits is likely to be complex and the values wouldchange over time, and possibly by location. At current levels of DG penetration, they are also likely tobe relatively small. Thus, in order to reduce complexity and administration costs, the APVArecommends that, until DG penetration levels increase substantially, such benefits, to the extent thatthey accrue to utilities, should be seen as compensation for any additional costs incurred by them inmanaging DG.

4 Are there additional costs to retailers associated with serving PV customers?

There may be some additional billing administration costs associated with a customer having PVelectricity. If net metering is applied, these will be very small because the customer ‘usage’ charge iscalculated by simply multiplying the net electricity import or export by the appropriate tariff. This canbe done for ToU tariffs as long as the amount of PV electricity exported is known for each time band.Any other payment arrangement for PV (for example a different feed-in tariff for exported electricity)will result in higher administration costs.

Ausgrid applied to the Australian Energy Regulator (AER) for a pass through amount for theadditional costs it incurred as a result of the NSW Solar Bonus Scheme (separate to the direct costsassociated with the feed-in tariffs). Even at the very high levels of PV uptake driven by the SBS, the AERrejected this application on the basis that the costs incurred were not sufficiently material to justifycompensation.

Note that the Service Availability Charge already covers the retailer’s customer-related operatingcosts and customer acquisition and retention costs – and so any such administration costs associatedwith PV would not affect the ‘usage’ charge, and so cannot be used to argue against net metering.

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5 Are there alternative approaches to estimating the financial gain to retailers as a result oftheir solar PV customers exporting electricity to the grid?

Quite possibly, although as discussed above, approaches such as those that attempt to value DGelectricity based on aggregation of component values (such as wholesale electricity costs) are likely tobe very complex, require site-specific assessments, and be less accurate.

6 What is the most appropriate approach to estimating the market value of the electricityexported by solar PV customers to the grid? What are the key issues that need to beconsidered?

While the spot price variation reflects the premium value of the PV electricity, increasing customerloads on the NEM, especially peak demand, will require future investment in peaking plant, which willbecome financially viable at a higher cost than the current generation mix. Given the correlation of PVoutput with spot prices (see figure below), it is likely that PV generated electricity can defer the need toupgrade peaking generation capacity. The value of the PV electricity should therefore be compared tothe LRMC of new peaking plant, rather than the LRMC of the least-cost generators or the average spotprice (which reflects the SRMC of existing generators).

Figure 1: SA Solar and Wind duration curves with the corresponding NEM price 2008-097

As an example of the difference this might make, the LRMC of new gas peaking plant in NSW wasestimated by ACIL Tasman (2009)8 to be in the range of $50-64/MWh ($2009-10), and the SRMC in the

7Boerema, N., 2010, Renewable Energy Integration into the NEM: Characterising the Energy Value of solar and wind

generation, Thesis submitted for Bachelor of Energineering in Renewable Energy, School of PV and Renewable EnergyEngineering, Uni of NSW.

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range of $29-42/MWh. The estimated 2011-12 SRMC of existing coal generators in NSW is in the rangeof $12-30/MWh ($A2009-10).

Other possible benefits from solar PV generation

7 What impact does solar PV generation have on network costs? How can this impact be mostaccurately measured?

Distributed PV generation results in reduced network usage, which can lead in turn to deferral ofupgrades. The impact of PV on networks is time and location specific and thus cannot be generalised.Its impact will increasingly be measured in reduced NEM, substation and customer loads. Note that theextent to which PV, or any DG technology, affects network costs is only relevant to a retailer to theextent that such effects are passed on from the DNSP to the retailer. Further, such impacts are onlyrelevant to the tariff paid for exported electricity to the extent that they affect the variable componentof the network costs passed on to the retailer.

European Commission supported DG-GRID and SOLID-DER projects have found that at low levels ofpenetration, PV has no impact on network reinforcement costs, energy losses decrease, and capacityupgrades can be delayed in the case of load growth, while investments can be reduced in the case ofequipment replacement9.

Note: Setting tariffs for exported electricity too low will encourage load switching to time ofgeneration. Where network demand peaks coincide with PV output, such load shifting could make thedemand peaks worse.

In the longer term, a review is needed by AEMC of distribution tariffs and regulations required toprovide an appropriate framework for efficient operation of smart grids, demand management, energyefficiency and DG technologies. At that stage, consideration could be given to additional valuesaccruing per MVA reduction of peak demand/capacity charges in addition to energy payments, in orderto encourage reductions at appropriate times and especially at parts of the network approachingcapacity constraints.

Concerns about reverse power flow, harmonics, voltage control and other potential impacts of highPV penetration levels need to be investigated and appropriate quality of service standards,performance requirements, and network protection put in place for all DG. Monitoring andcomprehensive network system modelling is required to estimate these impacts and determine theappropriate policy framework to encourage optimal behaviour from customers, retailers and DGs.

8ACIL Tasman (2009). Fuel resource, new entry and generation costs in the NEM, Prepared for the Inter-Regional Planning

Committee.9

FrÌas, P., T. GÛmez, et al. (2009). "Improvements in current European network regulation to facilitate the integration ofdistributed generation." International Journal of Electrical Power & Energy Systems 31(9): 445-451.

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The following provides a brief summary of findings from recent publications on reductions in peakdemand due to PV. In summary, PV shows a much better correlation to commercial load profiles thanto residential load profiles. Note that the contribution of other DG technologies (such as electricvehicles) to network support will depend on their characteristics as well as the pricing and regulatoryregime under which they are operating.

Country Energy Network Performance:

Our initial estimate is that network demand could be reduced by as much as 20 per cent ofthe connected PV capacity in locations where there is good overlap between generationand network loading.

Watt, Oliphant et al10:

For feeders with high residential loads which peak in the late afternoon, PV can reduce loadprior to the peak event, thereby potentially reducing transformer heating, however,contribution to the peak load itself is low.

For feeders with a mixed load, including commercial and industrial, and for the overallsystem load, the PV contribution can be more significant.

Looking at the PV output in all three States during the peak week highlights the advantageof distributed installations of PV which can smooth the PV output across a region to caterfor transient cloud cover.

Energy Australia DIMR (Newington):

From EnergyAustralia’s assessment, each kWp of installed PV capacity could be expected tolead to a reduction in inner metro peak demand of between 0.1 and 0.6 kWA. At least 75%of the time it would be 0.4 kVA or better.

Grid Connected PV Systems: 11

The 3.4 MW reduction in the highest load point means that 29.5% of the assumed 11.54MW (10x current PV) was contributing directly to offsetting the peak load.

PV and Commercial Loads12

Previous work by the authors has found that at any one time, PV provides between 30%and 75% of its rated capacity during peak periods

10M. E. Watt, M. Oliphant, H. Outhred & R. Collins (2003), “Using PV to Meet Peak Summer Electricity Loads”,

Proceedings of Destination Renewables, 41st

Conference of the Australian and New Zealand Solar Energy Society,Melbourne, November, 2003.

11M. Watt, R. Morgan & R. Passey, (2006), "Experiences with Residential Grid-Connected Photovoltaic Systems in

Australia", paper presented at Solar 2006, ANZSES Annual Conference, Canberra 13-15 September 2006

12Watt, M., Passey, R. and Snow, M. (2007) “The Contribution of Photovoltaics to Commercial Loads”, ANZSES Solar 2007

Conference Proceedings, Alice Springs, 2nd-6th Oct 2007

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Kogarah Town Square13:

The time of peak PV output and the time of peak site load correlated well (Figure 2), so itwas expected that reduction in peak demand would be close to the peak output of the PV.The amount of demand reduction, however, represented only 35% of the availablecapacity.

Figure 2: PV production, load and resultant load reduction at Kogarah Town Square

Carlton zone substation14:

To mimic the effect of a large number of similar installations, we multiplied the KogarahTown Square PV production data by one hundred. On this basis, the contribution of the PVto reducing zone peak demand would be 24% of the available capacity of PV.

13Energy Australia, 2005, Kogarah Town Square Photovoltaic Power System - Demand Management Analysis, for the NSW

Department of Planning.

14Energy Australia, 2005, Kogarah Town Square Photovoltaic Power System - Demand Management Analysis, for the

NSW Department of Planning.

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Value of PV in summer Peaks15:

15M. Watt, M. Oliphant, H. Outhred, I. MacGill, E. Spooner and S. Partlin (2005) Photovoltaics and Peak Electricity Loads,

Summer 2003-04, Report prepared for the BCSE, May 2005.

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SEDO- WA (CEEM, 2008)16:

It was found that the SWIS (Perth) locations’ peak load periods generally had a good overallcorrelation to either simulated north-facing or west-facing PV. However, where there weresignificant residential loads, the peak tended to occur later in the day, and so PV was not assuccessful in offsetting peak load. For example, if the very highest point of a load durationcurve was reduced by 0.9MW with 2MW of PV, this means that PV contributed 45% of itsrated capacity at that time. For the SWIS locations this contribution ranged from 33% to60%, and from 21% to 55% on average for the top ten load periods

The Edge of SWIS locations’ peak load periods were generally not well matched to eithersimulated north-facing or west-facing PV. It was found that the regional locations’ peakload periods were generally well matched to either simulated north-facing or west-facingPV. However, sometimes periods of slightly lower peaks were not as well matched to thesimulated PV, and so became the highest peaks. In these regional areas, PV’s contributionto reducing the load duration curve as a percentage of its rated output ranged from 25% to85%, and from 52% to 73% on average for the top ten load periods.

8 How can any network benefits resulting from solar PV generation be shared with solar PVcustomers?

Reduced losses and deferral of upgrades will automatically be of benefit to all customers. Whensetting a tariff for exported electricity, there is a need to differentiate between the benefits received bythe network operators and the resultant benefits that are then passed on to retailers, eg. through thefixed or variable component of the network charges.

To the extent that PV electricity avoids the per kWh network charges, it should be fullycompensated by the retailer for avoiding those charges. As discussed above, retailers are currentlyrequired to pay the full DUOS charges on all exported electricity when it is on-sold, even when thatelectricity is used either by the system owner or their neighbour. Removal of these DUOS charges onPV electricity would mean that PV electricity would avoid all the variable network charges faced by aretailer.

Deferral of generation may already be occurring as a result of PV installations. Since this generationis at the user interface, it implies a corresponding reduction in network use:

http://www.smh.com.au/business/solar-does-nsw-a-power-of-good-20110830-1jk5l.html

“The boom in solar panel installations coupled with higher electricity prices and energy efficiencymeasures has pushed back the likely need for new baseload electricity generation capacity in NSW untilnear the end of the decade. In the annual Statement of Opportunities issued by the Australian EnergyMarket Operator (AEMO) today, that need has been pushed back to 2018-19, a further two-year delaysince last year's forecast.

1.16

Passey, R., Watt, M., Outhred, H., Spooner, T. and Snow, M. (2007) Study of Grid-connect Photovoltaic Systems -Benefits, Opportunities, Barriers and Strategies, for The Office of Energy, Western Australian Government.

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A factor in the extended delay has been the 500 to 600 megawatts of solar panel capacity that isbeing installed following the state government's generous feed-in tariff subsidy, which has now beencurtailed.”

9 How should any value from reduced energy losses as a result of solar PV generation beestimated?

All transmission losses are avoided by distributed PV. All distribution losses are avoided on self-consumed electricity (including that counted as exported on a gross feed-in tariff but then consumedon-site), and the distribution losses for all other exported electricity would be extremely small as itwould be consumed by nearby loads. At much higher penetrations than current, electricity exported byDG may need to travel further, however, as shown in Figure 3, the current levels of penetration are verylow.

This figure shows PV penetration (number of systems / number of accounts) for each LGA inAusgrid’s area (green), and the proportion of PV electricity that is exported as a proportion of the totalconsumption in the local area (blue). Note that this overstates physical export, as gross meteringclassifies all generation as ‘beyond-meter export’, when it is likely less than 40% is physically exported.

Figure 3: PV Penetration and exports AusGrid 2010

The use of net metering would automatically reward DG for the losses avoided by the retailer(assuming these are currently accurately reflected in their retail ‘usage’ prices). If net metering is notused and so a more complex approach is required, AEMO already calculates reduced loss factors formajor embedded generators, and the same approach could be used:http://www.aemo.com.au/electricityops/0171-0010.pdf (see page 13 table c2). The volume weightedaverage approach could be used for each DNSP area if required.

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The report ‘Value of Generation from Small Scale Residential PV Systems’,17 includes a gooddiscussion on the various issues that should be considered.

10 If the value of reduced energy losses is material, should it be shared with solar PV customers?If so, how could this be achieved?

The benefit of reduced energy losses should be passed on to those who paid for them – the owners ofDG systems. Given that both transmission and distribution losses affect the retailer’s energy costs (ie.their per kWh costs), the most logical way to reward DG for avoided losses is through the per kWh‘usage’ charges. As discussed in Question 9, the use of net metering would automatically reward DG forthe losses avoided by the retailer (assuming these are currently accurately reflected in their retail‘usage’ prices).

Implications of setting the feed-in tariff too high or too low

11 What are the implications of setting the feed-in tariff too high or too low? What is the mostappropriate way of managing this risk?

The most obvious consequences of setting the feed-in tariff too low is that DG of all types will notbe deployed to the extent that is economically and socially optimal. The converse may also be true,particularly with regard to uptake rates. The optimal price will most likely vary over time and it will bevery difficult to get the price exactly right. This highlights the need for developing a flexible approachto set an appropriate feed-in tariff that reflects DG’s costs and benefits over time and so results inoptimal levels of deployment.

Assessing retail market competition

12 Is our proposed approach for analysing the effectiveness of retail market competitionappropriate for this review? Are there any other factors we should consider?

The current approach assumes that distributed energy solutions are able to compete equally withgrid supply in the market. The APVA feels that this is not the case and that a regulated minimum pricefor DG be provided until such time as a DG market is established.

17SKM/MMA (2011) Value of Generation from Small Scale Residential PV Systems’ by SKM/MMA for the Clean Energy

Council.

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13 Are there any barriers (or emerging barriers) to entry that may limit the potential forcompetition in the NSW retail electricity markets, particularly in relation to solar PVcustomers?

As PV prices fall, more customers will wish to displace purchased electricity with their own, lowercost generation. Restrictions placed on PV installation by retailers or networks will prevent individualsfrom reducing their electricity costs.

If electricity retailers capture a significant part of the PV market, through offers linked to their ownelectricity sales, competition from independent PV suppliers may be reduced, which in the longer termmay impact competitiveness. Origin is already Australia’s largest installer, and AGL has recentlyacquired Rezeko to make them 6th-largest. Such increases in market power may be sufficient toinfluence PV prices, STC prices, customer choice of retailer and hence electricity prices.

At the same time, continually changing policy arrangements have made PV a risky proposition forsmall business, with even well established businesses now closing.

14 Are there any other developments that may affect the competitiveness of the retailelectricity market in NSW?

Because the current retail market rules do not adequately support distributed energy solutions,there may be an increased shift to micro-grid operation, which can by-pass existing retail arrangementsand establish an independent market for energy services. The City of Sydney is currently proposingsuch a solution, with provision of electricity, heat, water and waste services within its micro-grid.

For customer who cannot readily avail themselves of such solutions, increased self reliance via PV,solar water heaters and zero energy homes may see the current retail market arrangements irrelevantin a few year’s time.

15 Has there been any change in the types of customers being offered competitive contracts? Isthere any evidence to suggest that there are particular groups of customers (particularly solarPV customers) that have been more or less active in the competitive market, such aspensioners?

APVA has no current information on this.

16 What evidence is available on the number of solar PV customers receiving voluntary feed-intariffs? Does the level of these voluntary feed-in tariffs represent a fair and reasonable valueof the electricity exported by solar PV customers?

Information on the number of customers receiving voluntary feed-in tariffs should be readilyavailable from the electricity retailers operating in NSW. Whether voluntary feed-in tariffs representfair and reasonable value should be assessed from the point of view of those that pay them – the

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electricity retailers. As stated throughout this submission, we do not believe the 6-8c/kWh represents afair and reasonable value of the electricity exported by solar PV customers.

Form of regulation

17 What degree of regulatory intervention is required to ensure solar PV customers receive afair and reasonable value for the electricity they export to the grid? Are there options (otherthan those listed in section 4.2) that are more appropriate?

It is likely that regulation of only the Standard Retailers would be sufficient to ensure that secondtier retailers would provide equivalent offerings. As stated in the Issues Paper, if the market issufficiently competitive, setting the feed-in tariff at a benchmark rate rather than at a specified ratewould indeed be an interesting test of the retailer’s perceived value of PV electricity to them. However,this does assume a sufficiently competitive market and also assumes that each Standard Retailer has anaccurate understanding of the value of PV electricity to them – neither of which is necessarily true. Inaddition, as discussed at the beginning of this submission, there are values that accrue to society ingeneral that are not necessarily captured in current prices – even assuming that a price is placed ongreenhouse emissions. Thus, the level of regulatory intervention that is required to ensure that DG isdeployed to the extent that is economically and socially optimal most likely involves a specifiedminimum feed-in tariff.

18 Should IPART recommend a single year feed-in tariff? If so, how should the feed-in tariff beupdated over time?

In the short term, assuming that DUOS and RET charges can be removed and so net metering fairlyapplied, there is no need to update the feed-in tariff over time as it will simply track the relevant‘usage’ tariff. Where the feed-in tariff is different to the relevant ‘usage’ tariff, minimum feed-in tariffsshould be set when regulated tariffs are reviewed, since they will be based on the relevant energy andnetwork costs at the time.

From the perspective of the solar industry, the consumer’s investment certainty is more importantthan a ‘perfect’ feed-in tariff. In this case, the most likely approach to deliver sufficient certainty is atransparent and easy to understand process for setting the feed-in tariff based on the installed cost ofPV systems (or other DG technology), current retail ‘usage’ tariffs and an assumed rate of export.

At such time as a market for distributed energy services is established in the NEM, thesearrangements will become redundant.

19 Should there be a limit on the size of the customer or solar PV unit that is eligible for this fairand reasonable value? If so, what should this limit be?

No, the 1:1 net metering default should be consistently applied across all size ranges for systemseligible to be connected to a distribution feeder. Large customers tend to negotiate electricity rates

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once every 3-5 years, which don’t necessarily coincide with their PV purchasing interests (or applicablepersonnel). Their tariffs may well be lower than regulated residential retail tariffs. There may need tobe some limit based on the proportion of electricity likely to be exported at times of low load, butotherwise a 1:1 arrangement would work equally well for large customers connecting into thedistribution network as for smaller ones.

20 Should there be a single feed-in tariff across NSW or should it vary by distribution networksupply area?

Following from 18, this implies that different tariffs may apply in different regions. As above, in theshort term, assuming that DUOS and RET charges can be removed and so net metering fairly applied,the appropriate tariff would automatically apply in different regions. With other feed-in tariff designs,it is entirely possible that the tariff will vary by distribution network supply area. The PV industry willhandle such regional complexity so long as clear maps of applicable regions are publically provided.

21 Should there be different feed-in tariffs for different customer types (eg business andresidential?)

No, the 1:1 net metering default should be consistently applied across all size ranges for systemsconnected to a distribution feeder, regardless of customer type. This is consistent with the method ofsetting the retail electricity tariff cap. Again, in the short term, assuming that DUOS and RET chargescan be removed and so net metering fairly applied, the appropriate tariff would automatically reflectthe value of PV electricity relevant to each customer type. In the longer term, assuming that the feed-in tariff is less than the relevant ‘usage’ tariff, it is difficult to see why the methodology should bedifferent for different customer types.

22 Should the feed-in tariffs vary by tariff component? For example, should there be a peak rate,a shoulder rate and an off-peak rate for customers with time-of-use metering and a standard(or block rate) for customers with accumulation meters?

The 1:1 net metering default should automatically apply to the different tariff rates, however, forsmaller customers, there may be merit in setting a fixed value which takes a weighted average of thetime of use benefits. Of course, with net metering and digital meters, the tariff paid to the systemowner should automatically be the value of that electricity to the retailer – who was responsible forsetting their TOU tariffs.

23 Should the feed-in tariff apply to both net and gross metering, or net metering only?

The intention of this question is unclear. It is unclear why the feed-in tariff would apply toelectricity exported under, for example, net metering, but not under gross metering. The feed-in tariff

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should apply to both types and customers should be allowed to decide what sort of metering systemthey prefer.

Retailer contribution to the Solar Bonus Scheme

24 How should we estimate an appropriate contribution of retailers to the Solar Bonus Scheme?

The answer to this question should simply be the same as the rate decided on to represent the fairand reasonable value of PV electricity to the retailer. It is unclear why it would be any different.

25 What are the key issues that need to be considered in recommending a contribution byretailers to the Solar Bonus Scheme?

The key issues should be the same as those relevant to determining the fair and reasonable value ofPV electricity to the retailer. It is unclear why it would be any different.

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Attachment B: Background on the APVA

The APVA is an association of companies, government agencies, individuals, universities and researchinstitutions with an interest in solar photovoltaic electricity. In addition to Australian activities, weprovide the structure through which Australia participates in an International Energy Agency (IEA)programme called PVPS (Photovoltaic Power Systems), which in turn is made up of a number ofactivities concerning PV performance and implementation. Further information is available fromwww.apva.org.au.

APVA Objective

The objective of the Australian PV Association is to encourage participation of Australianorganisations in PV technology and industry development, policy analysis, standards and accreditation,advocacy and collaborative research and development projects concerning photovoltaic solarelectricity.

APVA membership provides:

Information

Up to date information on new PV developments around the world (research, productdevelopment, policy, marketing strategies) as well as issues arising

Access to PV sites and PV data from around the world

International experiences with strategies, standards, technologies and policies

Australian PV data and information

Standards impacting on PV applications

Networking

Access to international PV networks (PV industry, government, researchers) which allow personalrelationships to develop and can be invaluable in business, research or policy development orinformation exchange generally

Opportunity to participate in international projects, with associated shared knowledge andunderstanding

Opportunity to meet regularly and discuss specific issues which are of international, as well as localinterest. This provides opportunities for joint work, reduces duplication of effort and keepseveryone up to date on current issues.

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Marketing Australian Products and Expertise

Opportunities for Australian input (and hence influence on) PV guidelines and standardsdevelopment. This ensures both that Australian products are not excluded from internationalmarkets and that Australian product developers are aware of likely international guidelines.

Using the information and networks detailed above to promote Australian products and expertise.

Working with international network partners to further develop products and services.

Using the network to enter into new markets and open new business opportunities in Australia.

The International Energy Agency PV Power Systems Programme (IEA PVPS)

One principal activity of the APVA is to manage Australian participation in the PVPS Programme.This work is arranged by Tasks, each with its own commitments of time and resources. Support isprovided by the Australian Solar Institute. At present Australia participates in:

Task 1: PV Information Exchange and Dissemination

Task 11: PV Hybrid Systems within Mini-grids

Task 14: High Penetration of PV in (Smart) Electricity Grids

and maintains an interest in:

Task 8: Very Large-Scale PV Systems

Task 9: PV in Developing Regions

Task 13: PV System Performance

For further information on the Australian PV Association visit: www.apva.org.au

For further information on the IEA PVPS Programme visit www.iea-pvps.org.