electricity reform

I N T E R N AT I O N A LE N E RGY AG E N CY

ENERGYMARKETREFORM1974 .1999

ELECTRICITYREFORM

Power Generation Costsand Investment

Col 2 OK 14/11/00 17:24

ENERGYMARKETREFORM

I N T E R N AT I O N A LE N E RGY AG E N CY

1974 .1999

ELECTRICITYREFORM

Power Generation Costsand Investment

INTERNATIONALENERGY AGENCY

9, rue de la Fédération,75739 Paris Cedex 15, France

The International Energy Agency (IEA) is anautonomous body which was established inNovember 1974 within the framework of theOrganisation for Economic Co-operation andDevelopment (OECD) to implement an inter-national energy programme.It carries out a comprehensive programme ofenergy co-operation among twenty four*of theOECD's twenty nine Member countries.The basic aims of the IEA are:

■ To maintain and improve systems for copingwith oil supply disruptions;

■ To promote rational energy policies in a glo-bal context through co-operative relations withnon-Member countries, industry and interna-tional organisations;

■ To operate a permanent information systemon the international oil market;

■ To improve the world’s energy supply anddemand structure by developing alternativeenergy sources and increasing the efficiencyof energy use;

■ To assist in the integration of environmentaland energy policies.

*IEA Member countries: Australia, Austria,Belgium, Canada, Denmark, Finland, France,Germany, Greece, Hungary, Ireland, Italy,Japan, Luxembourg, the Netherlands, NewZealand, Norway, Portugal, Spain, Sweden,Switzerland, Turkey, the United Kingdom,the United States. The European Commissionalso takes part in the work of the IEA.

ORGANISATION FORECONOMIC CO-OPERATION

AND DEVELOPMENT

Pursuant to Article 1 of the Convention signedin Paris on 14th December 1960, and whichcame into force on 30th September 1961, theOrganisation for Economic Co-operation andDevelopment (OECD) shall promote policiesdesigned:

■ To achieve the highest sustainable economicgrowth and employment and a rising standardof living in Member countries, while maintainingfinancial stability, and thus to contribute to thedevelopment of the world economy;

■ To contribute to sound economic expansionin Member as well as non-Member countriesin the process of economic development ; and

■ To contribute to the expansion of worldtrade on a multilateral, non-discriminatory basisin accordance with international obligations.

The original Member countries of the OECDare Austria, Belgium, Canada, Denmark,France, Germany, Greece, Iceland, Ireland,Italy, Luxembourg, the Netherlands, Norway,Portugal, Spain, Sweden, Switzerland, Turkey,the United Kingdom and the United States.The following countries became Memberssubsequently through accession at the datesindicated hereafter : Japan (28th April 1964),Finland (28th January1969), Australia (7thJune 1971), New Zealand (29th May 1973),Mexico (18th May 1994), the Czech Republic(21st December 1995), Hungary (7th May1996), Poland (22nd November 1996) andthe Republic of Korea (12th December 1996).The Commission of the European Communitiestakes part in the work of the OECD (Article 13of the OECD Convention).

© OECD/IEA, 1999Applications for permission to reproduce or translate all or part of this publication

should be made to: Head of Publications Service, OECD2, rue André-Pascal, 75775 Paris Cedex 16, France.

FOREWORD

Electricity markets within the OECD and around the world arebeing rapidly reformed.After decades of structural immobility inelectricity supply, governments are allowing market forces toplay an increasing role in the operation of supply systems andthe allocation of investment in new generating capacity. MostOECD Member countries have already introduced competitioninto their electricity systems or plan to do so soon.The main goalof these changes is to improve the economic performance ofelectricity supply, but other goals such as security of supply andenvironmental protection remain very important.

The prospect of lower electricity prices is a key motivation forreform. The first part of this booklet examines how electricityreform is expected to reduce generation costs. It confirms thescope for cost improvements, although it is the market whichultimately will determine their extent.

The second part considers how investment in the power sectorwill be affected by market liberalisation. Some observers fearthat the additional uncertainties to which the transition givesrise will result in inadequate investment in new generationcapacity or an inappropriate plant mix. Our analysis suggeststhat these issues will not deter investment, provided reform iswell designed in the first place and effective regulation is put inplace. Other markets, including other energy markets, haveproved capable of sustaining adequate investments. A residualresponsibility rests on governments, however, to monitor marketdevelopments and maintain an adequate regulatory framework.Governments must ensure that adequate incentives are in placeto attract new investment well before capacity shortagesappear. In the end, experience will demonstrate how wellelectricity reform measures up to expectations, but our analysisprovides good grounds for confidence.

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The principal authors of this report are John Paffenbarger(costs), Gudrun Lammers (investment), and Carlos Ocaña(investment).The Appendix on Energy Investment was preparedjointly by the Energy Charter Secretariat and the IEA for the G8Energy Ministerial in Moscow in 1998.

This book is published under my authority as Executive Directorof the International Energy Agency.

Robert PriddleExecutive Director

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TABLE OF CONTENTS

EXECUTIVE SUMMARY 9

Impact of Market Liberalisation on Generation Costs 9

Investment in Generation Capacity inCompetitive Electricity Markets 10

■ Determinants of Investment 11■ Prices in Oligopolistic Electricity Markets 11■ Minimising Risk in Electricity Investments 12■ Input Fuel Prices and Diversity 12■ Dynamics: the Impact of the Business Cycle

on Investment 12■ Reserve Generating Capacity

and Capacity Payments 13■ Transition Issues: Regulatory Risk 14

The Role of Governments 14

Global Energy Investments 15

IMPACTS OF ELECTRICITY MARKETLIBERALISATIONON GENERATION COSTS 17

Introduction 17

Market Liberalisation 18

Transparency of Public Policy Objectives and Costs 20

Allocation of Risks 22

Investment Costs 27■ Emphasis on Economic Designs 28■ Improved Use of Generation Capacity 29■ Repowering 31■ Competitive Procurement 31■ Cost of Capital 32

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Operations and Maintenance Costs 35■ Labour Productivity 35■ Operating Productivity 37

Fuel Costs 38

Separation of Functions 41

Conclusions 41

INVESTMENT IN POWER GENERATINGCAPACITY IN COMPETITIVEELECTRICITY MARKETS 43

Introduction 43

Investment in the Past 45■ How Investment Decisions Were Made 45■ Investment in the Past: Results 49

Investment under Competition 55■ A Framework for Understanding

Investment Decisions 55■ Electricity Prices and Markets 58■ Investment and Risk Mitigation 59■ Investment, Reserve Capacity and

the Business Cycle 62■ Transition Issues: Minimising Regulatory Risk 66■ Diversity of Input Fuels 67■ Empirical Evidence 68

Conclusions 70

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APPENDIX : ENERGY INVESTMENT 73

Executive Summary 73

Introduction 76

Energy Investment Needs and Benefits 76■ Energy Investment Needs 76■ Investments in the Oil and Gas Sectors 80■ Investments in the Coal Sector 83■ Investment in the Electricity Sector 84■ Investments in Energy Efficiency and Environment 87■ Benefits from Investments in the Energy Sector 89

Conditions for Investment in the Energy Sector 91■ Risk - Distribution and Reduction 91■ Access to Investment Opportunities 92■ Operation Once the Investment is Made 103

Recommendations to Governments on Energy Investment 111

REFERENCES 115

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LIST OF TABLES AND FIGURES

TABLES

1. Examples of Public Policy ObjectivesImplemented by Utilities 21

2. Typical Risks Faced by Electricity Generators 23

3. Average Annual Decrease in Utility EmploymentDue to Market Liberalisation 36

4. CEGB Estimates of NEC of Future Power Stations(Pounds/kW, 1982 prices) 47

5. Capacity Growth and Reserve Marginsin OECD Countries 50

FIGURES

1. US Median Nuclear Plant Outage Times,1989-1998 30

2. Employment Trend in US Investor-Owned Utilities,1986 -1995 37

3. Evolution of Generating Capacity Reserve Marginsin Selected OECD Countries 51

4. Generating Capacity Reserve Marginsin OECD Countries (1997) 52

5. OECD National Fuel Shares in Electricity Production(1997) 53

6. Coal- and Gas-Fired Capacity Additionsin OECD Europe, 1950-1999 54

BOX

1. Defining Electricity for Policy Making 44

EXECUTIVE SUMMARYGovernments throughout the OECD are restructuring theirelectricity supply industries to reduce the direct role of the stateand to introduce competition. Key objectives of these changes areto increase the economic efficiency of electricity supply and toobtain lower prices for electricity consumers. Maintaining securitythanks to timely and adequate investment in new generation capacitywith an adequate plant mix remains an important objective as well.This booklet confirms that market liberalisation is likely to lead toreduced generation costs, while preserving security of supply interms of system reliability and adequacy of investment.

Impact of Market Liberalisationon Generation Costs

Although the introduction of competition in electricity supply isrelatively new, preliminary results from those countriesimplementing reforms show that there is pressure to reduceinvestment and operating costs. One effect of market liberalisationis to expose the cost of meeting public policy objectives. Examplesare the cost of supporting uneconomic domestic coal mining, orsupporting domestic equipment suppliers. Market liberalisationrequires governments to shift such expenses from within theinternal accounts of power generation companies to explicit,publicly accessible accounts. Generation costs should decrease asthe cost of meeting policy objectives is allocated to other accounts.

In a competitive electricity market electric utilities cannot auto-matically pass costs through to all consumers, since revenues aredetermined by market success and not by regulatory formulae.Thishas the effect of increasing uncertainty and risks borne by investorsin the electric supply industry and increasing the cost of equity anddebt finance. On the other hand, utility business risks can decreaseas a result of a reduction in certain regulatory risks and a betterallocation of risks to parties able to take action to mitigate them.

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There can be, therefore, opposing influences on the cost of capital(and total finance costs) as electricity markets are liberalised. In thegeneral case, it can be expected that the cost of capital for newgeneration capacity will increase as it approaches its “normal”market level reflecting the cost of capital in other, similar industries.Regardless of the direction of variation, investment choices shouldbetter reflect the full costs of alternatives.

Investments costs will decrease in liberalised markets through agreater emphasis on economic designs, improved use of generatingcapacity, repowering, and competitive procurement.There are newincentives to avoid over-building and over-designing power plants.Operations and maintenance costs will decrease due to greaterlabour productivity and operating productivity.These results weresome of the first observed in electricity markets that have beenliberalised to date. Fuel costs should also decrease due to improvedfuel management, better use of fuel supply contracts and markets,and a reduction in the consumption of high-cost, domestic fuels.

In summary, market liberalisation is likely to focus attention on thecosts of generation and provide strong incentives for generators toreduce their costs. For publicly owned utilities, a key factor inimproving cost performance is the greater transparency inimplementing public policy measures brought about bycorporatisation or privatisation. For utilities with supply monopolies,the loss of captive customers and price competition are the essentialdrivers. Markets, rather more than governments, will allocate costsbetween customers and utility investors, providing generators withnew motivation for efficient operation.

Investment in Generation Capacityin Competitive Electricity Markets

Adequate, timely and appropriate investment is essential to ensuresecurity of electricity supply. The analysis concludes thatinvestment in electricity generating capacity can be undertakeneffectively in the context of liberalised electricity markets. Provided

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that effective competitive markets are established, which includesempowering end-users of electricity with choice, more efficientinvestment can be expected and long-term system reliability can besustained.

■ Determinants of Investment

Before the onset of competition, investment decisions were generallytaken by the state or other public authorities, directly or indirectly,taking account of the whole power generation system.Whilst thisapproach was intended to minimise total system cost, high reliabilitylevels and over-optimistic demand forecasts resulted in largeamounts of excess capacity in some countries.This was partly dueto unexpected economic circumstances, including a slowdown inthe rate of economic growth. However, it was also a result ofplanning incentives which biased investment decisions towardover-investment.

In competitive markets, investment decisions are largely determinedby current and expected prices. Many prices influence investmentdecisions in generation assets. To understand how investmentdecisions will be made under competition it is useful to considerthe impact of three sets of prices that are likely to be the maindeterminants of investment decisions. These are the price ofelectricity, the cost (or price) of capital, and the price of input fuels.Prices, in turn, depend on supply and demand factors like thewillingness of users to pay for electricity and security of supply, orelectricity demand growth. At an economy-wide level, pricesfluctuate with the business cycle.

■ Prices in Oligopolistic Electricity Markets

So far, the evidence is that significant market concentration is afeature of most OECD countries’ electricity supply industries, atleast in the early stages of the market reform.This “oligopolistic”market structure generally has the effect of maintaining prices at arelatively high level, which allows firms to earn above-marketprofits.This, in turn, encourages investment.

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■ Minimising Risk in Electricity Investments

Increased business risk in competitive electricity markets would, intheory, tend to reduce total investment in electricity generation.

In practice, this effect can be expected to be small and can begenerally compensated by other factors. Greater risks are matchedby greater potential rewards, notably higher profit margins.Furthermore, various financial techniques available in competitivemarkets allow companies to reduce their investment risks. Indeed,evidence suggests that investment in merchant plants is acceleratingin markets open to competition; it could be expected that anexplicit valuation of security would further increase the attractive-ness of merchant plants.

■ Input Fuel Prices and Diversity

The relative prices of input fuels also play a critical role in shapinginvestment decisions and are among the main determinants in thechoice of fuels. In the past, there have been significant fluctuationsin fuel prices which have resulted in large shifts in investment fromone input fuel to another. Most recently this has been mostly infavour of gas, helped by technology developments in combined-cycle gas turbines.The overall result of past investment patterns isa higher (although unintended) degree of input fuel diversity. Thesame pattern may continue under competition as relative pricescontinue to change over time. Currently, in many regions of theworld, gas-fired generation is the most economical option. As aresult, the share of gas-fired electricity generation is growing at theexpense of oil and coal, resulting in more diversity.

■ Dynamics: the Impact of the Business Cycleon Investment

An often debated issue is the impact of the business cycle oninvestment. Electricity prices may be expected to follow a cyclicalvariation along the business cycle reflecting the relative scarcity ofgeneration capacity relative to electricity demand.The question is

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how will investment react to the variability of electricity prices. Ifinvestors are too concerned with short-term price levels, or“myopic,” then investment could well go through pronounced cycles.If, more plausibly, the expectations of investors are rational, theninvestment cycles may be less pronounced or even negligible.Appropriate incentives, such as financial penalties in case of non-delivery, could reinforce this. In any case, this is an empirical issuethat can only be resolved after some years of experience. Duringthis transition period, it will be up to the governments to monitorthe situation and to intervene if they judge it to be necessary.

More importantly, there are factors that can mitigate any investmentlags. These factors include new technology which shortensconstruction times, the options to re-power existing plants, andthe “demand smoothing” potential of peak-load pricing.

■ Reserve Generating Capacityand Capacity Payments

Some governments have been concerned that reserve capacity maybe at risk in a more competitive market and that ad hocmechanisms, such as capacity payments, might be needed to ensurean adequate reserve capacity. The principal argument against theneed for such mechanisms is that prices in a competitive marketshould reflect the value to the buyer of reserve capacity, as well asany other component of security. In particular, contracts betweenproviders and buyers of electricity should include the characteristicsof the security of supply to be provided and the penalties for failingto deliver.This suggests that there are natural market mechanismsthat can provide sufficient incentives to invest in reserve capacity.Such market mechanisms may either be set up by the regulators orby the market players themselves.

If, despite this, there is concern about future reserve capacity, or ifpolicy makers want an explicit market for capacity, there are anumber of policy tools available, including capacity payments.However, at least for as long as some generators enjoy market

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power, capacity payments carry some disadvantages and may resultin significant market distortions.

■ Transition Issues: Regulatory Risk

The transition from regulated to open electricity markets ofteninvolves significant uncertainties. The end point of reform is notalways clearly defined and reform often proceeds gradually. Inaddition, the implicit regulations that often pervade the oldarrangements have to be made explicit in a process that takes timeto complete. As a result, there may be considerable regulatory riskin the transition to competitive electricity markets. Regulatory risk,like other risks, may discourage investment.Although this effect istransitory, it may be significant, especially where additional investmentis needed at the time of opening the market to competition.Governments have a key role in minimising regulatory risk. Acredible and clearly defined regulatory framework for electricitymarkets is essential to facilitate investment.

The Role of Governments

In the short to medium term, changes in security of supplyconditions (investment, input fuel diversity) can be expected toevolve slowly. Power markets are unlikely to become fiercelycompetitive in the near future. Many countries have opted forgradual liberalisation. Nevertheless, governments still have animportant role in this new environment to mitigate potentialproblems. Governments should:

■ Ensure as far as possible that an effective market, includingcompetition in generation and end user choice is established.Address market entry barriers to generation.

■ Monitor the market structure and possible anti-competitivebehaviour of market participants to sustain effective entry intothe market and effective consumer choice.

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■ Establish well-funded, well-staffed and competent regulatorsand anti-trust enforcement agencies to prevent the emergenceof barriers to new generation entry.

■ Monitor system reliability and investment in generation.However, unless the monitoring indicates real problems,governments should refrain from interfering. The monitoringneeds to be adapted to the size of the market. In some cases, itmight have to be done at international level, in others atnational or subnational level.

■ Monitor input fuel diversity and estimate the extent to whichsecurity of supply is ensured by the market. If remedial action isneeded, measures at economy-wide or energy market level arepotentially more effective. Measures restricted to the electricitymarket are a second-best solution because they ignore alternativefuel uses. If they are the only feasible solution, they should bemarket-based.

■ Create a favourable investment climate by providing a credibleand clear regulatory framework and streamlining the adminis-trative process for construction permits as far as possiblewithout jeopardising other important regulatory concerns (e.g.,compliance with safety and environmental regulations). ManyOECD countries have cumbersome procedures that considerablylengthen lead times.

Global Energy Investments

Ensuring adequate investments in electricity supply is part of thelarger issue of ensuring adequate energy investments in general.This larger question was considered by energy ministers of the G8countries1 at their meeting in Moscow of 1 April 1998. A paperwritten jointly by the IEA and the Energy Charter Secretariat forthis meeting is given in an appendix to this booklet.

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1. Canada, Germany, France, Italy, Japan, Russia, the United Kingdom, the United States.

The ability of countries to mobilise enough capital for their energyinvestment needs depends on the quality of their investment, fiscaland regulatory policies. This in turn crucially affects the rate ofeconomic growth and living standards in those countries.

One of the most important considerations for potential investorsis a country’s political and economic stability. Companies alsoevaluate other market, financial and legal risks.The main areas aremarket access, including market structure, discrimination andbureaucracy and market operation, including the legal framework,the financial environment and market conditions.

Companies want assurance that they can obtain authorisationsneeded for new investments. Procedures must be based on clearand consistent criteria and should minimise bureaucraticcomplexities and delays. Foreign investors will be particularlydeterred if there is discrimination on nationality grounds.Companieswill want to be sure that they can, if necessary, protect theirinvestments by recourse to law, including whenever necessaryaccess to international arbitration.

Traditionally, in many countries, the scope for private sectoractivity in the energy field has been limited by the involvement ofgovernment and State enterprises. There is now widespreadrecognition that liberalisation, including privatisations andreduction of monopolies, improves the economic efficiency ofenergy markets. Governments need to ensure fair competition,including control of monopoly behaviour, and avoid distortions inenergy prices.

In countries where appropriate legal and/or fiscal regimes are stillbeing developed or have not long been in place, governments needto take positive action to create investor confidence throughstrong and stable legal guarantees. Features of the national environ-ment that are important to companies investing in the energysector are a stable and effective legal environment, a pattern oflegal and fiscal stability, proper taxation rules, and secure access onfair terms to trade and to energy transport systems, such aselectricity grids.

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IMPACTS OF ELECTRICITYMARKET LIBERALISATION ONGENERATION COSTS

Introduction

This chapter describes how liberalisation of electricity marketsis likely to affect the costs of electricity generation. Marketliberalisation refers to the world-wide trend which aims toimprove the economic efficiency of electricity supply industries byintroducing elements of competition and moving toward market-based pricing. It shifts decision-making from government entities tothe market. A basic objective of market liberalisation is to reduceprices paid by consumers for electricity. Where prices do notreflect the full costs incurred in supplying electricity, as is the casein some developing countries, market liberalisation aims to bringprices up to fully cover expenses. Related key objectives of marketliberalisation may be to reduce government funding of state-ownedutilities and to improve the international competitive position ofdomestic industries (and utilities).

Market liberalisation affects not only price levels, but the underlyingcost structure. It generally provides incentives for a more efficientcost structure and will affect profit margins on costs of supply,costs of transmission and distribution, and costs of generation.Generation cost is the focus of this chapter.

Today there are few quantitative results on the cost effects ofelectricity market liberalisation because the movement toliberalised markets is a relatively recent phenomenon.Within theOECD, about three quarters of countries now have national orstate-level competitive generation markets covering at least aportion of total electricity demand. In the remaining OECDcountries without competitive electricity markets, non-utilitygenerators are allowed to sell electricity to the monopoly utility ordirectly to large consumers. Most countries began the process of

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impacts of electricity market liberalisation on generation costs2

liberalisation in the 1990s, although the US legislation dates from1978. The European Union Directive on electricity marketliberalisation was agreed only in 1996. Therefore, the reasoningpresented in this chapter rests primarily on economic expectations,but has not yet had the time to be tested or observed widely innational markets. Some observations of cost trends in markets thathave been liberalised are given below.

Market Liberalisation

The term “market liberalisation” covers a number of related reformsto electricity supply industries which are not necessarily all pursuedat the same time.They are:

■ corporatisation – placing state-owned utilities into commerciallystructured and commercially oriented companies;

■ privatisation – transfer of assets of the electricity industry fromstate to privately owned organisations;

■ deregulation – reducing direct state control or oversight ofvarious aspects of industry operations;

■ introduction of competition – allowing more than one electricitysupplier to compete for customers in a given market.

Transmission and distribution of electricity are commonlyconsidered today as monopoly system elements not subject tocompetition. Introducing competition in generation has thereforebeen the focus of many reform efforts to date. The marketing ofelectricity to end-users is also potentially a competitive componentof the electricity supply industry.

The approach to market liberalisation in each market dependsintimately on the starting point of the industry.This is defined byownership, horizontal and vertical structure of sub-sectors, andexisting regulation of the industry. State ownership of the industryis common. Beyond this generality there is an enormous variationin different electricity systems. In some countries there are many

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privately owned electricity generators and/or suppliers, while inothers there is one dominant utility, owned by the state in nearlyall cases. Regulation ranges from no formal control whatsoever, asis common in systems with large, state-owned utility companies, toindependent, adversarial regulation as in the United Kingdom orthe United States.

The type of reforms pursued to liberalise electricity markets havedifferent effects and provide different incentives to electricitygenerators to change their economic behaviour. Clearly, however, aprimary focus is to reduce power generation costs ($/MWh).Corporatised state-owned utilities may reduce costs as moretransparent accounting procedures reveal any existing sub-optimalor politically constrained spending patterns. Privatised utilities mayreduce costs in order to increase profits for their new owners.Generators in newly competitive markets will try to reduce costsin order to compete effectively. In all cases, market liberalisation isexpected to:

■ increase efforts to reduce expenditure on generation andmaximise returns to plant owners;

■ re-orient decision-making to incorporate private rather thanpublic economics;

■ lead to more transparent and effective pricing to better reflectcosts.

The potential for cost reduction varies by country and utility. Somesystems are relatively efficient already, while others have largescope for cost improvements. There are wide variations in coststructure among utilities. For example, the average accountingvalue of thermal and nuclear plant capital costs vary by factors of4.5 and 4.8 among UNIPEDE member countries (Olarreaga, 1993:p. 8). Among OECD Member countries, system losses vary from2% to over 15%, and nationally averaged efficiencies of thermalpower plants vary by over 10 percentage points (IEA, 1997). Notall such system cost and performance variations are due touncontrollable, local factors such as accounting conventions, plant

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mix, or plant ages. Some are attributable to real variations in theefficiency of use of factor inputs. One study of US utilities suggeststhat efficiency of operation accounts for 60% of the variations inaverage system prices (Haeri, 1997).

Short-term actions taken in response to market liberalisation differfrom actions possible in the long term. In the short term, thecapital stock is not changeable, so generators tend to focus onreducing operations and maintenance expense, improving assetmanagement, and improving capital (financial) management. In thelong term, new investments and new technology will be sought toprovide a new generation plant mix having lower total cost.

Transparency of Public Policy Objectivesand Costs

One effect of many approaches to market liberalisation is toexpose the cost of meeting public policy objectives. In non-competitive environments, governments have had a number ofmechanisms at their disposal to accomplish public policy objectiveswithout incurring any identifiable public or private expense. Thiswas achieved by assigning responsibility for executing policies toutilities, which bore the costs through state ownership, regulation,or in a “co-operative spirit.” The expenses could be passed onquietly and diffusely to ratepayers. In the case of state-ownedutilities, the costs could be recouped by reducing contributions togovernment treasuries (low or no dividends) or by obtaining largeryearly operating funds from the government. Regardless ofownership, the mechanisms have often not been transparent.

Examples of public policy objectives implemented by governmentsvia electric utility companies are given in Table 1.

All of the mechanisms noted in Table 1 can result in the selectionof generating capacity on non-economic criteria.The cost of usingmore expensive generation options may thus not be discerniblewithin the cost of the overall generating mix.

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In markets where generation becomes open to competition,individual decisions on generating capacity will no longer take intoaccount non-economic requirements unless they are made explicitby regulation and all potential competitors are subject to them.Instead, individual plant developers will aim to provide electricity atthe lowest possible cost by minimising cost of fuel, equipment, andlabour within the set of environmental regulations applicable to allcompetitors (note parallel with examples in Table 1).Any potentialgenerator required to fulfil certain objectives from which others

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Table 1

Examples of Public Policy Objectives Implemented by Utilities

Policy Objective Mechanism via Requirements on Utilities

Support domestic ■ domestic coal purchase agreementscoal mining ■ utility ownership of un-economic coal mines

Promote energy security ■ selection of particular fuel sources for power generation

■ prohibition on specific fuels

Support domestic ■ use of non-competitive procurement proceduresequipment suppliers ■ selection of non-commercial generation technology

Support employment ■ over-use of labour by state-owned utilities

Reduce pollutant ■ selection of specific environmental controlemissions technologies (not necessarily needed to meet

environmental regulations)■ selection of particular generation technologies

Promote renewable ■ selection of renewable technologiesenergy ■ required purchase of power produced using

specific renewable sources■ favourable pricing for purchases of electricity

produced using renewables

Note: Example mechanisms are actions utilities may be required or encouraged to take even in the absenceof specific regulation or legislation.

are exempt can justify a claim of discriminatory treatment and willcall attention to the effects of the policy requirements. Policy costspreviously borne by the generation sector in non-competitivesystems will thus be made transparent with the arrival ofcompetition.

State-owned companies are apt to benefit from special financialadvantages which help them to fulfil a policy role. For example, theymay pay no income taxes, may have access to less expensive debtthrough government bond markets, or may have access to certaingovernment services at no cost. Corporatisation or privatisation ofstate-owned electric utilities, even without introducing competition,may expose some of these off-book financial benefits.This in itselfis a major impact of privatisation.

Although the advent of competition can expose the cost of publicpolicies administered through electric utilities, many of the policygoals remain valid. Long-standing policy objectives, such as securityof supply, environmental protection, and social objectives, must beexplicitly considered in new arrangements for the electricity sector(IEA, 1999;Tonn, 1995).

Allocation of Risks

Market liberalisation has the effect of increasing risks borne byinvestors in the electric supply industry and decreasing price riskto consumers. In the non-competitive model,many mis-calculationsof future costs can be passed on to electricity consumers in higherprices. In state-owned systems, the state can choose to acceptlower returns from its utilities or provide direct financial supportin order to compensate for mis-calculations. In contrast, it is theinvestors in electricity utility companies who bear more of theoverall business risk in liberalised markets. Electricity generationbecomes more like any other business, where consumers rewardcompanies that are well managed and avoid companies that err.

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Examples of the types of risks faced in generating electricity aregiven in Table 2.These risks exist regardless of the regulation andorganisation of the industry.What varies is the actions utilities taketo protect against these risks, and who ultimately bears the cost ofthese risks should they materialise.

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Table 2

Typical Risks Faced by Electricity Generators

Type of Risk Outcome Compared to Expectation

Constructioncost overruns ■ construction costs more

schedule delays ■ long construction time; purchased replacementpower may be needed to meet shortfall

technology ■ poor plant performance, especially when usingnew technology

■ low plant efficiency; low plant availability

financial ■ high plant financing costs

Operatingmarket ■ low electricity sales, leading to excess capacity

■ major customers find alternate supplies■ low electricity sales price

operations and maint. ■ high labour or material costs

fuel ■ high fuel price■ inadequate fuel quantities

financial ■ returns are lower than expected■ capital is poorly structured

Policyregulatory ■ regulations result in higher costs

■ administrative procedures cause delays■ tax burden increases

environmental ■ environmental laws become stricter■ environment assessment criteria change

siting ■ land purchased for a plant becomes ineligible

Since expenses reasonably incurred could be passed on toconsumers or borne by state owners, the tendency in traditionalelectricity markets has been for utilities to avoid risks throughextra investment to mitigate possible problems and to avoidnegotiating too aggressively in plant procurement, particularly withequipment suppliers. The balancing of potential risk and actualexpenditure to avoid risk did not necessarily seek to minimisecosts of generation, but rather sought to minimise risks (financial,political, or other) to the utility itself. The conservative or “risk-averse” attitude of many monopoly supply utilities is well known.As a result, many argue that utilities have probably spent more ongenerating assets than they would have in competitive markets byover-designing and over-building plant capacity. “Over-designing”refers to incorporating power plant features which increase theunit cost of electricity without satisfying a fundamental designconstraint such as performance or safety.“Over-building” refers toproviding amounts of plant capacity to meet conservative (high)estimates of growth in electricity demand. The result has beenrelatively high reserve margins in many electricity supply systems.

Utilities may have also spent more on plant operations than theywould have in competitive markets. Costs that might have beenavoided through, for example, contractual means were notnecessarily considered carefully, unless they were ultimately borneby the utility owners. Examples include accepting ambitiousconstruction schedules without builder guarantees, using unprovedtechnology without vendor guarantees, or accepting long-term fuelsupply contracts at premium prices.

The development of independent power producers (IPPs) has, inmany electricity supply systems, made the nature of electricitysupply risks particularly evident (see Paffenbarger, 1997a). Beingoutside the traditional supply system, IPPs were not able to pass onrisks through the monopoly regulatory arrangements and insteadgenerally relied upon a series of contracts to allocate risksexplicitly. Fixed-price construction contracts transfer someconstruction risks to the architect-engineer. Operations and

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maintenance agreements transfer operating risk to a separateoperating contractor. Most importantly, a power purchaseagreement often transfers market, fuel, regulatory, and environ-mental risks to the monopoly utility which purchases theelectricity produced. This utility has normally been required topurchase the electricity from a defined set of eligible producers atregulated prices, and has been allowed to pass the cost of theseelectricity purchases to its own customers. Ultimately then, manyof the risks faced by IPPs have been passed on to electricitycustomers through the purchasing utility, but through explicitcontracts. These arrangements are not feasible in competitiveelectricity generation markets.

Private owners of electric utilities have historically enjoyed stablereturns on their investments due to the traditional allocation ofrisks. In the United States, for example, return on utility bonds havebeen only slightly higher than those earned on US Treasury bonds,an essentially risk-free investment.The variability of returns on USutility assets has been among the lowest of any industry (Brealey,1984). In Spain, returns to private utility owners have been essentiallythe same as on government securities.

In liberalised electricity markets, investors are likely to face greatervariability in their returns, which should move toward the averagefor similar industries. Unexpected costs can be passed on toconsumers only to the extent that all utilities face the same costsand attempt to reflect the costs in their prices. Utilities that do notmake adequate provisions for minimising risk, or which over-spendto avoid risk, will not be able to recover costs in their prices, whichare set by the market rather than by regulation. Utility investorsmust absorb such costs.

Investors include two broad categories: debt holders and share-holders. Of the two, shareholders face the most risk. Shareholdersare not guaranteed fixed dividends, but obtain their returns fromthe profits of the company. On the other hand, debt holders haveinvested in loans and bonds with defined rates of return. In the case

25


of severe business difficulties, debt holders have first right to theassets of the utility, and so are more likely to recover theirinvestment than share holders. Both classes of investor will faceincreased risk in liberalised markets.

There is some debate as to what increased investor risk will do tooverall costs of capital for electric power generation. It is clear thatincreased risk will translate into higher cost of equity sinceshareholders will seek a higher return in compensation.This is animplication of all financial models, such as the capital asset pricingmodel or the discounted cash flow model of dividends. However,the size of the increase required to compensate for the increasedrisk is not easily predictable. It depends on expected industryperformance over a period of years, which is in turn influenced bythe nature of industry competition and regulation.The cost of debtmay, on average, increase, but this also is difficult to predict. Evenunder non-competitive systems electric utilities face financialdifficulties and bankruptcy. The arrival of competition will notnecessarily lead to lower average quality of debt in the industryand, as a result, higher average costs of debt.The effect of cost ofcapital on investment costs is discussed further below.

Market liberalisation is likely to reduce costs of generation bybetter allocating risk to those parties that can take action tomitigate it. In non-competitive systems consumers implicitly absorbrisks because they can take no organised action to reduce them,such as switching to a different electricity supplier with a betterrisk management strategy. In liberalised markets, that option maybe open to them. In competitive markets, utility investors havestronger incentives to reduce risks cost effectively.They are in thebest position to allocate risks through such measures asestablishing better contractual arrangements, entering into newbusiness relationships, purchasing financial hedging instruments, andpurchasing insurance. They are under competitive pressures toavoid incurring excessive costs, so over-designing and over-buildingare less likely to be successful business strategies.

26


The above discussion assumes that the period of marketliberalisation is complete and operation of the market has reacheda stable, long-term pattern. However, regulatory and market risksmay be different during the initial transitional period of marketliberalisation than in the long term. On the one hand, some risksborne by investors are likely to be greater during the transitionperiod. The political and technical decisions needed to finalise allthe arrangements for the new system take time to develop, andinitial paths may be subsequently changed. Business arrangementsand existing contracts take time to re-establish, and there isuncertainty as to the best choices for the future.The behaviour ofcustomers during an initial period of market opening is also difficultto predict with certainty. On the other hand, the inherited marketstructure and some transitional arrangements, such as paymentsfor stranded costs and gradual market opening, are likely to reducerisks. These points suggest that at least some risks borne byinvestors will be greater during the transition period, but not allrisks. In the short term the largest risks and areas of greatestuncertainty could tend to delay or reduce the potential for costreductions due to market liberalisation.

Investment Costs

The debate on whether or not utilities should be compensated for“stranded assets” in liberalising markets has shown that investmentcosts under traditional electricity markets have not always been aslow as possible. Stranded assets are those unamortised costs ofprior investments that would be recovered by monopoly supplyutilities but which would not be recovered under competition dueto lower electricity prices. High capital costs are not the onlysource of stranded assets, but they are a significant component.TheUS Department of Energy estimated stranded assets in the UnitedStates would range from US$ 72 to 169 billion, out of a total assetvalue of about $400 billion (EIA,1997) if regional competitive marketshad been in place at the beginning of 1998.The 1996 privatisationof the nuclear generating utility British Energy brought in £1.4 billion,

27


even though the company’s newest generating station, Sizewell B,was completed in 1995 at a total cost of over £3 billion.This is notto suggest that only traditional electricity markets are subject toproblems of stranded investments. Liberalised markets cannot avoidlosses in plant investment values either, but it is true that they willprovide stronger incentives to avoid excessive investments.

■ Emphasis on Economic Designs

As noted above, there are strong disincentives to over-designingpower plants. Liberalised markets focus attention on the choice ofpower plant features and technology which result in lowest productcost. Extraneous design features or design constraints which maybe common, but which do not provide a clear economic advantage,are therefore likely to fall from use. Utilities in turn put pressureon equipment suppliers to rationalise designs and cut costs ofmajor equipment.

There is some evidence of this in the United States, where moststates have been preparing for or debating the introduction ofcompetition for several years. Costs for coal-fired power plantshave declined by one third since 1993. Capital costs for combinedcycle power plants in the United States have declined from over600 $/kWe in the early 1990s to below 400 $/kWe in 1996(Hansen, 1996). Designs of combined-cycle plants have becomesimpler over time and manufacturers have responded to costpressures by developing standardised plant designs.

Admittedly the precise influence of competition is difficult todiscern because of parallel developments in technology and amongpower equipment suppliers. Technological developments in gasturbines have certainly aided the world-wide decline in turbineprices in the last decade. Equipment suppliers have been underpressure to cut prices, not only from generators facing theprospects of competition, but also from equipment manufacturingovercapacity, particularly among boiler manufacturers.

28


■ Improved Use of Generation Capacity

Capacity utilisation is likely to increase in liberalised markets.Thatis, generators will make every effort to ensure that capacity factorsof generating plants are as high as possible, that plant production ismaximised when electricity prices are highest, that unplanned outagesare minimised, and that rarely used capacity is minimised. Highercapacity factors can dramatically lower the final cost of generationas capital costs are spread over more units of electrical output.

Again the United States provides an indication of the trend towardshigher capacity utilisation in liberalising markets. From 1984 to1993 in the United States, the average availability of coal-firedplants increased from 76 to 81% (EIA, 1997: p. 16), and from 1991to 1998, the average capacity factor of nuclear plants rose from70 to 80% (NEI, 1999). In Australia, the percentage availability ofthe Yallourn 1 and Hazelwood coal-fired plants operating in thecompetitive Victoria power market increased from the low 60s in1991/92 to the 80s in 1995/96 (Dillon, 1996). A third plant, LoyYang A, increased its availability from 78% to over 90% in the sameperiod. In the United Kingdom, the availability of National Power’spower stations increased by 3 percentage points in the five yearsfollowing privatisation (NP, 1995).

There has been a world-wide trend in recent years towardsimproved utilisation of nuclear plants. Part of this improvementis due to technological progress and accumulation of operatingexperience, but part may also be attributed to competitivepressures in some nuclear markets (Finland, Sweden, UnitedKingdom, United States). Outage times for both refuelling andother common procedures such as replacing steam generatorshave been steadily declining. In the United States, nuclear refuellingoutages have dropped steadily since 1989, as shown in Figure 1, andthe record time continues to fall at individual plants.

System reserve margins are likely to fall in competitive markets, asgenerators strive to minimise unused generation. Depending onhow the electricity market is structured, demand-side bidding for

29


capacity can promote this. Demand-side bidding provides a meansfor customers to sell capacity into a spot electricity market byreducing load during periods of peak demand. This effectivelyreduces the requirement to provide infrequently used peak capacity.Another feature of liberalising markets which tends to reduce theneed for peak capacity is “time-of-use” pricing.This sets electricityprice over time periods (hourly, daily or seasonal periods) tobetter match the marginal costs of production.When productioncosts are high, prices will be higher, for example during the peakdemand period of the day. Electricity consumers thus have anincentive to reduce demand when production costs are highest.This pricing scheme is by no means unique to competitive markets,but may be introduced or strengthened at the same time as marketrestructuring. In systems with spot markets for electricity, thewholesale electricity price automatically follows the variations in

30


Figure 1

US Median Nuclear Plant Outage Times, 1989-1998

0

10

20

30

40

50

60

70

80

90

1998199719961995199419931992199119901989

Med

ian

Out

age

Tim

e (d

ays)

Source: Institute of Nuclear Power Operations

production cost through generator price bids.The development ofless expensive, more sophisticated metering might lead to real-time pricing and help to reduce peak demand from domestic andcommercial consumers.

■ Repowering

Repowering of old facilities can provide a means to increase theeffectiveness of existing capacity and minimise capital investment innew capacity. Repowering means the replacement of a significantportion of the plant to improve its performance and reduce costs.Old facilities are typically dispatched infrequently because of highmarginal operating costs or operational constraints. Thermalefficiency may be low. Repowering can in some cases effectivelyprovide new capacity at lower installed cost and thereby takeadvantage of existing investments in infrastructure, manpower, andfuel supply.

■ Competitive Procurement

Liberalising markets can result in a weakening of links betweennational or state-owned utilities and domestic equipmentsuppliers. Monopsony buying of power generation equipment andservices has been raised as an issue by equipment manufacturerswho have felt excluded from some markets and by internationalbodies concerned with trade. Monopsony markets are markets inwhich there is only one major buyer or a few buyers. In powergeneration equipment, a dominant national utility may rely onhigher-priced domestic equipment as a matter of governmentpolicy or guidance. It can be argued that governments have explicitlyencouraged reliance on domestic equipment suppliers as anelement of industrial or regional development policy, employmentpolicy, or technology policy.The US turbine manufacturer GeneralElectric argued in a highly publicised 1993 court case (nowresolved amicably) that the German utility VEAG unfairly excludedit from a supply contract in favour of a domestic supplier. TheItalian competition authority criticised the state supplier ENEL in1996 for relying almost exclusively on Italian equipment suppliers

31


(PIE, 1996). These domestic suppliers not only provided 99% ofENEL’s equipment from 1991 to 1994, but also tended to offer verysimilar prices, indicating a lack of competition.

In procurement of capital-intensive assets, there are only smallinherent advantages in working with local firms. They share thesame language, business practices, and technical standards and areoften the closest geographically.These are matters of conveniencerather than substantial economic value compared to the value ofpower plant equipment. As liberalising markets introducetransparency and emphasise cost-effectiveness, utilities will putpressure on domestic equipment suppliers to compete moresquarely on price.This is likely to reduce equipment costs in someelectricity markets.The drop in equipment prices in recent years isthought to be due, at least in part, to the pressure arising fromderegulation and privatisation of electricity markets around theworld (Wagstyl, 1997).

■ Cost of Capital

There can be opposing influences on the cost of capital aselectricity markets are liberalised.The cost of capital can increaseor decrease, depending on the starting regulatory and institutionalarrangements. In the general case, it can be expected that the costof capital for new generation capacity will increase as it approachesits “normal” market level reflecting the cost of capital in other,similar industries. Regardless of the direction of variation, anychange in cost of capital would reflect an adjustment in the broadallocation of capital resources within the electricity supply industry.Under competition, investment choices should better reflect thefull costs of alternatives.

It was noted above that utility owners will bear increasedcommercial risks in generating electricity in liberalised markets.Private owners of generating capacity may require higher returnson their equity investments than public owners. Increasedcommercial risks tend to increase the cost of raising both equityand debt for utility companies.They could possibly induce a decline

32


in the share of debt used to finance new investment.The realloca-tion of risks under competition thus tends to increase the cost ofcapital for new generation capacity.

Newly privatised utilities would typically see increases in their costof capital. In addition to having access to debt at low interest rates,state-owned utilities may be able to provide minimal or no returnon the state’s equity investment.Whereas government owners mayexpect no income stream from the utility, or may allow substantialvariations depending upon the utility’s annual financial results, privateowners insist upon a regular stream of dividends on their equity.Therefore, formerly state-owned utilities would face higher cost ofequity and debt.

The cost of capital will not necessarily increase in all marketsundergoing liberalisation.The opposite development could occur inmarkets where public owners use the electricity monopoly to fundgovernment activities. This is a well established situation amongmunicipal or local utilities in some OECD countries. Public ownersmay be able to withdraw more cash through high profitrequirements than would be possible by private owners or ownersoperating in a competitive market. In such situations, marketliberalisation might tend to decrease returns on equity anddecrease the effective cost of capital.

Another factor mitigating increases in the cost of capital is apotential reduction in certain regulatory risks faced by utilities.Under some regulated monopoly supply systems, there has beenincreased business risk in recent years from unexpected regulatoryactions. Some regulatory authorities and governments have morecritically evaluated costs incurred by monopoly supply utilities.Thedis-allowal of certain expenditures for nuclear power plants hasbeen a visible example of this. Some utilities in Germany, Spain,the United Kingdom, and the United States faced considerableuncertainty as to their ability to recover costs for construction ofnuclear power plants which were subsequently cancelled or notallowed to enter into operation. Some US utilities approached

33


bankruptcy before the issues were resolved fully. So-called“prudency reviews”2 in the United States dis-allowed other coststhought to be reasonable by the utility but unreasonable by stateregulatory authorities. Regulatory risk has increased uncertaintyand raised the cost of capital in some markets.

Competition in generation could reduce this component ofregulatory risk, since generators are responsible primarily toshareholders to see that expenses are incurred wisely.The market,rather than government, determines which expenses may bepassed on to consumers and which must be borne by investors.The reduction in regulatory risk (at least for generation costs)could partially offset the increase in business risk introduced bycompetition.

In the United Kingdom the real rate of return of the electricityindustry increased dramatically following privatisation, beginningfrom a value of less than 3% under state ownership. In the fiveyears following the corporatisation of the New Zealand state-utility, its rate of return on equity increased from 4% to 12% (Culy,1996: p. 347).

Higher costs of capital increase the relative importance of thecapital component of generation cost. If generators in liberalisedmarkets find the cost of capital to be higher than previously, boththe capital component of generating costs and the total generationcost will increase.There could be some effect upon the choice oftechnology and fuel as well. Higher costs of capital tend to favourless capital-intensive technologies and those with shorterconstruction times. For example, in moving from a 5% to a 10%cost of capital, nuclear plant levelised generation costs will typicallyincrease by about half, whereas those of gas-fired plants willincrease by less than 15% (see OECD, 1998).

34


2. Prudency reviews are financial examinations carried out by state or local electricity regulatory bodies todetermine whether or not certain expenses incurred by utilities can be considered prudent and, therefore,recoverable from electricity consumers. See discussion in Chapter 3 under “How investment decisions were made”.

The magnitude of the effect due to changing cost of capital isdifficult to assess. In cases where a state-owned utility enjoyed alow cost of capital, say 3%, private generators are likely to arrive atquite different choices in investment and design.Without access tocapital at low, government-backed interest rates, private utilitieswill have a greater incentive to minimise capital costs. However, itis not clear whether many systems will see large enough changesin cost of capital to result in changes in investment decisions. Inrecent years the trend towards the selection of gas turbines andcombined cycles, particularly in the United Kingdom and theUnited States, is often cited as evidence of the use of higher discountrates and shorter payback periods by generators. However, gas-fired plants in these markets are often the most economical choiceover a range of cost of capital used by incumbent utilities,independent power producers, and autoproducers.

Operations and Maintenance Costs

Non-fuel operations and maintenance expenses are typically thelargest single cost element of utility operations.They are a variablecost tied to output to a lesser degree than fuel, and so are theobject of particular scrutiny in utilities operating in liberalisedmarkets. Utility labour and operating productivity have risen inmany markets undergoing liberalisation.

■ Labour Productivity

Table 3 summarises decreases in electricity utility employment insystems undergoing market liberalisation. The decreases stemmainly from improvements in labour productivity and not decreasesin electricity production. Utilities facing competition have not onlysignificantly improved the use of labour for technical tasks, but havealso improved personnel management practices.The latter can beexpected to minimise non-productive time such as from shiftscheduling conflicts, absenteeism, or sickness. Some utilities havedeveloped multi-discipline training and more flexible team formation

35


to cut labour costs. They have reduced their work forces andlowered payroll expenses through attrition, layoffs, and earlyretirements.

36


Table 3

Average Annual Decrease in Utility EmploymentDue to Market Liberalisation

Country Form of Liberalisation Decrease Time(% of initial Period

value)

Victoria, privatisation, competition 10% 1989-96Australia

Hungary privatisation 4% 1995-97

New Zealand corporatisation 10% 1987-92

United Kingdom

National Power 13% 1990-95

PowerGen privatisation, competition 10% 1990-95

British Energy 7% 1996-98

United States* impending competition 3% 1990-96

Sources: Dillon, 1996 (Victoria); OECD, 1998, Annex 2 (Hungary); Culy 1996: p. 348 (New Zealand);corporate annual reports (United Kingdom); EIA, 1996: p. 87 (United States).

* major investor-owned utilities.

Other deregulated industries provide indications that liberalisationtypically improves labour productivity. In the United States,deregulation of the trucking industry led to a 25% drop in labourcosts. In commercial passenger air transport, yearly earnings offlight attendants and pilots dropped by 40% and 20% respectivelyfollowing deregulation (EIA, 1997: p. 68). In the US electricityindustry, the real value of salaries and wages decreased by 28%from 1986 to 1995 as the industry prepared for the arrival ofcompetition (EIA, 1996: p. 86). Figure 2 shows the marked trendtowards decreasing employment by investor-owned utilities since

1990. Staff reductions and salary pressures are likely to continue ascompetition emerges in individual state markets.

In nuclear power generation, staffing represents a relatively highproportion of non-fuel operations and maintenance costs.Improvements in labour productivity are particularly likely to occurin nuclear utilities entering liberalised markets.

37


Figure 2

Employment Trend in US Investor-Owned Utilities, 1986-1995

400

420

440

460

480

500

520

540

1995199419931992199119901989198819871986

Empl

oym

ent

(tho

usan

ds)

Source: EIA, 1996: p. 87

■ Operating Productivity

Non-labour improvements in operating productivity are alsolikely to occur in liberalising markets. This includes, for example,reductions in expenses for supplies, tools, or materials, moreefficient use of equipment, and increased maintenance effective-ness. Preventive maintenance is likely to be relied upon moreeffectively to balance maintenance costs with costs due tounplanned equipment failures.

In New Zealand following the corporatisation of state-ownedgenerators, unit operating costs in power stations decreased by13% over the period 1987 to 1992 (Culy, 1996: p. 347). In theUnited States, anticipated competition has contributed to a 50%reduction in expected operating expenses for new coal-fired plantscompared to 1993 values.

In nuclear plants, there has been a world-wide trend in recentyears toward improved operations and maintenance costperformance. The trend towards reduced time for maintenanceactivities requiring plant outages was noted above.At least part ofthese trends may be due to the arrival or imminent arrival ofcompetition. In the United Kingdom, for example, the nuclearutility Nuclear Electric reported that it cut the cost of its per unitoperations and maintenance expenses by 40% from 1989 to 1994at the same time as competition was introduced beginning in 1990(NW, 1994). In the United States, among other areas of improve-ment in recent years, the volume of low level wastes has decreasedand fuel reliability has increased (NN, 1997).

Fuel Costs

In most monopoly supply systems, fuel costs are passed on to finalconsumers.There is often little incentive to change the fuel mix orminimise fuel costs once plant technology/fuel choices have beenmade. In contrast, market liberalisation is likely to promote the useof the most economic fuel for local conditions, while complyingwith the relevant local constraints such as meeting environmentalstandards. Fuel costs can be reduced by a variety of means: examplesare increasing plant efficiency, changing the plant fuel mix, andimproving fuel contracting.

In the United Kingdom, National Power reduced its fuel costs perunit of electricity by 13% in the four years following privatisation(NP, 1995). Part of this was due to a shift from relatively expensivedomestic coal toward greater use of natural gas. In the UnitedStates, real operations and maintenance costs decreased by 22%

38


from 1986 to 1995, mostly due to a reduction in total fuel expenses(EIA, 1996: p. 86). Lower fuel prices and transportation certainlyplayed the most important role, but part of the pressure on pricesand transportation costs came from utility awareness of impendingcompetition. US coal-fired power plants have increasingly soughtlow-cost fuels compatible with coal co-firing.The use of petroleumcoke has increased dramatically in US utility boilers in recent years(Paffenbarger, 1997b: p. 38) because of its low price andcompatibility with existing plant systems. In addition, automobiletires and palletised wastes have been tested in a number of coal-fired boilers.

A move to shorter term fuel supply contracts is also likely tooccur, coupled with strategies to secure price stability. For example,some utilities may find it advantageous to take financial stakes infuel suppliers. It is likely that a greater variety of contract forms andpricing structures will emerge in liberalised electricity markets.Theparallel movement towards liberalised gas markets in Europe willprovide opportunities for utilities to revise their fuel purchasingstrategies.

There are potential pitfalls to changing fuel purchase arrangements.Focusing too much on minimising short-term fuel costs while nottaking adequate precautions against longer-term or sudden pricerises could lead to higher total fuel bills for individual utilities. Forexample, the use of interruptible gas supply contracts withoutmaking provisions for an adequate backup fuel supply could lead tothis result.The skill with which utilities balance short-term fuel billsand price risk will determine the extent of real savings.

Fuel costs may be lowered in multi-fuel power plants by takingadvantage of relatively brief changes in relative fuel prices. Forexample, if there is a seasonal or short-term increase in the priceof natural gas relative to fuel oil, a generator with access to bothfuels may switch a plant from natural gas to fuel oil to obtain alower fuel cost.The reverse sequence is equally possible if it is fueloil that increases in price. Dual firing allows a plant operator to

39


reduce the economic risk of changes in fuel prices and to minimisetotal fuel costs.The capital investment required for such capabilityis less than 5% of boiler investment cost for dual gas/oil firing.

An additional economic advantage for owners of dual-fuel plantswith firm fuel supply contracts is the ability to profit fromdifferences between contract and spot market fuel prices.Take theexample of a dual fuelled plant supplied under a non-interruptiblenatural gas contract. If the spot price rises relative to the contractprice, and fuel oil is available from the spot oil market or in theplant’s storage tanks, the plant could switch from natural gas to oiland sell natural gas on the natural gas spot market.The utility willprofit when the difference in price between spot and contract gasprices is greater than the extra cost of operating on fuel oil. Pricedifferentials of this sort are normally of short duration becausesupply contracts are typically indexed to spot market prices withsome time lag and averaging calculation. The technical ability toswitch rapidly between fuels is therefore key.The ability to realisearbitrage gains of this type depends on competitive gas supplymarkets.

The increased policy transparency characteristic of marketliberalisation is likely to reinforce the trend of reduced support ofdomestic coal mining industries through electric utilities. France,Germany, Japan, Spain,Turkey, and the United Kingdom have all hadpolicies which effectively encouraged or required utilities topurchase certain amounts of expensive domestic coal. Thesepolicies have been recognised as undesirable and all the countriesabove have taken steps to reduce such implicit subsidies in favourof explicit government support and eventual phase-out. In the caseof the United Kingdom this process has been accelerated by themove to a competitive electricity market. When the state-ownedutility was privatised, its successor companies decreased the use ofdomestic coal, largely by increasing the use of natural gas. Whenlong-term domestic supply contracts expired in 1998, coal costsfor United Kingdom plants decreased further.

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Separation of Functions

In markets where competitive generation is introduced, responsibilityfor electricity network functions traditionally borne by generatingplants may be assigned to a network operator or another party.As generation and supply of ancillary functions are separated, thetotal cost of generation and supply of ancillary network functionsis likely to increase, but generating costs may decrease.

Ancillary services are bundled with electricity generation intraditional electricity supply systems. These services includefunctions which ensure the stable operation of the network asloads shift in size and location on the grid:

■ controlling power flow and frequency;

■ supplying reactive power;

■ providing reserve capacity.

When ancillary services are provided jointly with generation,individual plants may not be operated in the most efficient way forpower generation alone. By separating generation and systemfunctions, the costs of providing each will become explicit infinancial accounts. It seems reasonable to expect that generators,by focusing on minimising “raw” generating costs, will be able tobetter minimise generating costs while drawing in a separaterevenue stream for providing system functions. Still, the actualeffect on generating costs is uncertain (Hill, 1996).

Conclusions

Market liberalisation is likely to focus attention on the costs ofgeneration and provide strong incentives for generators to reducetheir costs. For publicly owned utilities, a key factor in improvingcost performance is the greater transparency in implementingpublic policy measures brought about by corporatisation orprivatisation. For utilities with supply monopolies, the loss of

41


captive customers and price competition are the essential drivers.Markets, rather more than governments, will allocate costsbetween customers and utility investors, providing generators withnew motivation for efficient operation.

There are some indications of these trends in liberalising markets,although they are early and not conclusive. The anticipation ofcompetition, notably in the United States, appears to be a driverfor improving efficiency of utility operation and generation inparticular. Generators in the United Kingdom, Australia, andNew Zealand have shown substantial gains in productivity ascompetition has been introduced. Cost improvements have beenseen in other markets moving towards liberalisation and this willaccelerate as liberalisation takes hold in more countries both inOECD and around the world.

42


INVESTMENT IN POWERGENERATING CAPACITYIN COMPETITIVE ELECTRICITYMARKETS

Introduction

The liberalisation of the electricity supply industry in most OECDcountries has profound implications for investment decisions inpower generating capacity.Under competition, investment decisionsand the associated risks are primarily borne by investors. Beforecompetition, investment decisions tended to be in the hands of thepublic sector, and risk was borne by consumers. In fully liberalisedelectricity markets, demand — consumer preferences — willdetermine the amount and nature of investment.

This chapter considers the implications of the new investmentconditions for security of electricity supply.A central public policyobjective for the electricity sector, whether under competition ornot, is to ensure security of supply, both in the short and long-term.Security of electricity supply may be characterised in terms ofthree elements: short-term system reliability, long-term systemreliability through adequate investment, and long-term systemreliability through diversity/availability of input fuels. Security ofelectricity supply is a public policy objective in most, if not all,OECD countries because of the relatively limited substitutionpossibilities of electricity for other forms of energy linked to thefact that some of electricity’s uses are essential components ofmodern life. Box 1 defines electricity’s key characteristics for policymaking.

This chapter focuses on investment, that is, on long term systemreliability. It confines itself to investment in power generatingcapacity. Although investment in the electricity transmission anddistribution grids is also essential, and decisions concerning the

43

INVESTMENT IN POWER GENERATING CAPACITY IN COMPETITIVE ELECTRICITY MARKETS 3

latter are relevant to decisions on generating investments, thesematters are outside the scope of this study.

The basic question examined is: what are the implications of morecompetitive electricity markets for investment? This requiresconsideration of whether the new conditions could create problemsand, if so, what should be done about it.

44


Electricity can be defined as a composite good made up of energy which is(generally speaking) a non-storable commodity; transportation of electricitywhen required and the related co-ordination of transportation services (i.e.,system operation); and value added services (e.g., metering and billing)which, together with the commodity and transportation, make up supply tothe end-users.

Energy: The commodity component of electricity is similar to many othercommodities, but has some important particularities. Electricity demandfluctuates in the various time horizons (within a day, year, or business cycle)both randomly and non randomly. In addition, electricity cannot beeconomically stored.This means that generating (and transmission) capacityneeded to cope with peak demand is partly unused in periods of lowerdemand; reserve capacity may be required to cope with random demandfluctuations; and a diversified portfolio of electricity generating technologiesis needed to provide electricity at least cost. Linked to that, electricitygeneration is characterised by a merit order of generating plants. In varyingdegrees, generating technologies are also characterised by their relativelyhigh capital intensity, and technical and economic longevity, including longlead and construction times. Nevertheless, some recent innovations aredramatically lowering capital intensity and shortening lead and constructiontimes for some technologies.

Transportation: Transportation services have some natural monopolycharacteristics. Electricity networks exhibit significant economies of scale and

Box 1

Defining Electricity for Policy Making

Investment in the Past

■ How Investment Decisions Were Made

Under the past model of vertically integrated utilities enjoying astatutory monopoly, investment decisions were, at least in theory,taken through an approach that optimised the entire supply system— i.e. that minimised total system cost — rather than simplyassessing the profitability of one single power plant project. The

45


there are so-called “network externalities” (investments may benefit allinterconnected parties). It is customary to distinguish between two types oftransportation: transmission is transportation at very high voltage levels anddistribution is transportation at lower voltage levels. Transmission coverstransportation over an interconnected network, which is shared by all end-users, whereas distribution covers transportation from the interconnectednetwork to some end-users; a transmission line thus provides security ofsupply to all end users while a distribution line benefits only some.

System Operation: For technical reasons, co-ordinating transportationservices requires a centralised system operation. This intrinsically mono-polistic function can be unbundled from transportation, in which case anindependent system operator is in charge of this function.

Value-added Services: These are the services that (together with thecommodity and transportation) make up supply to end-users.They includean increasing number of activities like metering, billing, differentiation (e.g.,green energy) and packaging electricity (e.g., with other utility services),supplying differentiated reliability and quality, energy efficiency services,demand management etc.These activities do not have any special featuresfrom the point of view of regulation and policy making.

The regulatory changes taking place in the electricity supply industry consistof the unbundling of the components of electricity, and the liberalisation ofthe commodity and value added services components, which are potentiallycompetitive.

former UK Central Electricity Generating Board (CEGB) providesone example of this approach. For “essential” investment, theprocedure was roughly the following:

The CEGB based its plant-ordering decisions on two-stageinvestment planning models. In the first stage, a global programmingmodel was used to develop a background plan. This backgroundplan would set out, in very broad terms, an optimum pattern ofsystem development for forty to fifty years, taking intoconsideration expected demand growth, capital costs, operatingperformance, economic lifetime of alternative types of generatingcapacity, and price forecasts for the input fuels.

In the second stage, marginal or incremental studies were preparedfor individual investment projects. These studies were used torepresent and evaluate the economics of investment projects inmuch greater detail than was feasible in the background studies.For example, the background studies did not appropriately reflecttechnical progress and its impact on plant performance, i.e., did nottake into account that later commissioning dates meant thattechnical improvements could potentially be exploited, a factorthat is significant in practice.

The incremental studies began by forecasting future load (electricitydemand) duration curves. These curves were integrated, yieldingthe amount of electricity (the number of Gigawatt hours) neededalong all points of the load duration curve, and eventually thenumber of hours each type of plant capacity would have to run.Various types of power plant were then ranked according to theirrunning cost, and, in comparison with the utilisation hours justderived, the optimal plant mix was determined. This allowedoptimal investment in types of plant capacity to be determined (e.g.coal-fired, steam boiler or single-cycle gas turbine etc.).Taking intoaccount other, plant-related factors such as economies of scale,expected plant availability, expected operating lifetime etc., andusing a 5% real discount rate, a plant’s net present cost in Poundsper kW, per annum, was determined.The resulting figure, called thenet effective cost (NEC), was the key indicator of which investment

46


project was to be undertaken.The investment project(s) with thesmallest NEC would then be realised.

Separate calculations were carried out to determine whether aplant could be replaced on cost saving grounds. In this case, thepresent value of the cost saved by the replacement, called netavoided cost (NAC), was subtracted from the NEC. Whether toreplace the plant was determined on the basis of the lowestremaining figure.Table 4 illustrates the CEGB’s estimates of NECfor two types of power station, that were to be commissioned inthe early 1990s.

This type of overall system optimisation is, under idealcircumstances, equivalent with the outcome of an equally idealcompetitive market. In this highly theoretical sense, total systemoptimisation attempted to “mimic” competition.The reality can berather different.

Utilities’ demand forecasts often erred on the high side due to anumber of factors. First, there was a requirement to maintain avery high level of system reliability. Second, the planning mechanism

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Table 4

CEGB Estimates of NEC of Future Power Stations(Pounds/kW, 1982 prices)

PWR Coal-fired

Capacity-related (C):91 49Capital charges, provision for transmission equipment,

decommissioning, interest during construction

Fuel costs (F) 28 112

Other operating costs (O) 12 8

Fuel savings from displacing less efficient plant (S) 160 143

NEC (C + F + O - S) - 29 + 26

Source: Jones, 1989.

did not penalise upward biases in demand forecasts.Third, the highelectricity demand growth rates of 7% or more per annum thatprevailed during the 1960s were not adjusted quickly enough tothe depressed growth rates of GDP and electricity consumptionafter the two oil shocks of the 1970s. The IEA’s own energy andelectricity demand forecasts had, in fact, continuously overstatedGDP growth and electricity demand growth, and were reviseddownwards in subsequent issues of the World Energy Outlook.Fourth, as discussed in the previous chapter, there was little or noincentive to keep costs down since they could be “passed through”to consumers.

Utilities’ own investment decisions were also in many casesinfluenced or revised by government action. See Table 1 forexamples of government policies having an influence on investmentdecisions. Government influenced investment decisions not onlythrough technical, safety and siting control, but also often directlythrough investment control in the interest of consumerprotection.This was the case of the so-called “prudency reviews”in the United States. Investment control was also a means toinfluence utilities’ choice of primary input fuels in order to achieveenvironmental goals or to favour indigenous energy resources.

Investment prudency reviews were part of the widespread use ofcost-of-service regulation in State Public Utilities Commissions.Utilities had to submit detailed investment plans to prove that theirinvestment was “prudently” incurred and would be “used and useful”.Only in such case would the plant be included in the rate base.Multiplied with the allowable rate of return on capital set by theregulatory authorities; the rate base determines the averagerevenue utilities may charge their consumers, and therefore theirabsolute levels of profit.Thus, an investment project not includedin the rate base would not be profitable for a utility, and wouldtherefore not be undertaken. For an overview of price regulationsee Bonbright, Danielsen and Kamerschen, 1988.

In fact, it is this very mechanism which has created much of thepresent problem of stranded generation assets in the United States.

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Investments that were incurred in a prudent manner, and approvedby regulators as such, are becoming economically obsolete in acompetitive environment due to radically altered frameworkconditions, notably higher discount rates and an unexpectedly largepotential for cost reduction. Other elements have also contributedto stranded investment such as over-investment in the 1970s, orthe US Public Utility Regulatory Policies Act of 1978 that requiredutilities to purchase electricity at relatively high prices fromindependent power producers.

In the past, government or regulatory influence, often direct, on thetype of generating capacity chosen and the input fuels used wasexerted in a majority of OECD countries. The actual implemen-tation mechanisms varied across the OECD. Some governmentscontinue to exert such control.

■ Investment in the Past: Results

Electricity generating capacity grew steadily in OECD countriesfrom 1980 to 1996. On average, capacity grew at rates in the 2%-3%range over the period. Capacity additions have been roughly in linewith peak demand growth, thus yielding relatively stable reservemargins over the period (See Table 5).

Security of supply as measured by national reserve margins showslarge differences among OECD countries (See Figures 3 and 4).Thesmallest reserve margins (not including emerging economies) areclose to 20% (Belgium, Finland, Norway, Sweden, United Kingdom,and United States). At the other extreme, some countries havereserve margins above 40% (Denmark, Italy, Spain, and Switzerland).However, cross-country comparisons of reserve margins can bemisleading as differences in the technology portfolio (e.g., more orless hydro capacity), international electricity exchange capacity and,perhaps, demand patterns mean that different reserve marginswould be needed to achieve the same “effective” security of supplyin each country. Even so, the fact remains that reserve marginsdiffer significantly among OECD countries and that, under mostreasonable standards, some of these values seem to be large.

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Average AnnualReserve Margin (%)Capacity Growth (%)

81-85 86-90 91-95 95-97 1985 1990 1995 1997

Belgium 6 0 1 -1 38 26 21 19

Canada 4 1 3 -1 26 19 24 n.a.

Denmark 3 1 4 3 36 36 46 45

Finland 1 3 2 4 30 44 29 26

France 5 3 1 2 31 39 38 39

Germany 2 1 0 -1 27 25 29 27

Greece 5 3 0 3 42 42 32 30

Iceland 5 0 3 3 42 29 32 22

Ireland -1 1 2 3 34 32 24 22

Italy 4 0 3 3 n.a. 36 40 41

Japan 3 3 3 3 35 27 26 31

Netherlands -1 0 2 3 43 39 41 31

New Zealand 6 -1 2 1 37 29 32 28

Norway 2 2 1 1 27 37 27 31

Spain 6 2 1 3 46 42 44 44

Sweden 3 1 -1 1 27 32 27 27

Switzerland 2 0 1 0 49 45 46 47

Turkey 13 13 5 2 37 44 32 23

United Kingdom -1 2 0 2 21 26 21 21

United States 1 2 1 1 30 26 20 22

Table 5

Capacity Growth and Reserve Margins in OECD Countries

Source: IEA Electricity Information 1998.

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A significant feature in the evolution of reserve margins in OECDcountries is that, while most countries show some degree ofvariation over time, there are no instances of low (e.g. significantlybelow 20%) reserve margins.This supports the idea that regulated

51


investment regimes have been effective in ensuring that enoughgeneration capacity was available. It also suggests that plannershave not taken any risks of under-investing in generating capacitysince otherwise occasional episodes of relatively low reservemargins would be expected.The asymmetry of the incentives builtinto the investment planning system suggests an obvious explanationfor this pattern. Forecasting errors leading to over-investment mayhave resulted in higher electricity rates without generally carryingpenalties to the electricity supply industry or its regulators. On theother hand, forecasting errors leading to under-investment mighthave well resulted in social and political pressures to allocateresponsibilities.

Figure 3

Evolution of Generating Capacity Reserve Marginsin Selected OECD Countries

Res

erve

Mar

gin

15%

20%

25%

30%

35%

40%

UKUSAJapanGermanyFrance

1997199519901985

Source: IEA Electricity Information 1998

52


Figure 4

Generating Capacity Reserve Margins in OECD Countries (1997)

0% 10% 20% 30% 40% 50% 60%

Austria

Switzerland

Denmark

Spain

Italy

France

Portugal*

Hungary

Ireland*

Czech Republic

Netherlands

Norway

Japan

Belgium*

Iceland

Greece

Mexico

New Zealand

Germany

Sweden

Finland

Canada**

Turkey

United States

United Kingdom

Korea

Poland

Luxembourg*

Source: IEA Electricity Information 1998Notes: * 1996 data from UNIPEDE (1998). ** 1995 data

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Figure 5

OECD National Fuel Shares in Electricity Production (1997)

0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10%OtherRenewables

HydroNuclearNatural GasOilCoal

PolandAustralia

Czech RepublicGreece

DenmarkUnited States

GermanyIreland

OECD TotalPortugal

KoreaUnited Kingdom

SpainTurkey

NetherlandsHungary

FinlandBelgium

JapanCanadaAustriaMexico

ItalyLuxembourg

New ZealandFrance

SwedenNorwayIceland

Switzerland

Source: IEA Electricity Information 1998

Fuel shares in electricity production also vary widely among OECDcountries (see Figure 5). In several OECD countries generatingcapacity is fairly diversified among fossil fuels and nuclear. Theimportance of hydro generation varies greatly depending on eachcountry’s natural resources, while the weight of other renewablefuels in the fuel portfolio is uniformly small in all OECD countries.

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Figure 6

Coal- and Gas-Fired Capacity Additionsin OECD Europe, 1950-1999

MW

e

0

2000

4000

6000

8000

10000

12000

14000

coal gas1998199419901986198219781974197019661962195819541950

Source: UDI/McGraw-Hill,World Electric Power Plants Data Base, February 1999

Over time diversification of the fuel portfolio seems to have beenachieved in a rather discontinuous way. Figure 6 shows the patternof capacity additions in OECD Europe for coal-fired and gas-firedpower stations since 1950. The irregular path followed by thesetwo series suggests that the choice of fuel for electricity generationgoes through cycles. Furthermore, the timing of events suggeststhat investors have tended to favour the fuel that appeared to bemore promising at the time the decision was made. To sum up,

successive changes in expectations may have induced fuel diversityin the past. Even if more work would be required to test thishypothesis empirically, it suggests that changing expectations mayalso be a factor in determining fuel shares in a liberalised market,as technology, fuel reserves and other factors evolve over time.

Investment under Competition

■ A Framework for Understanding InvestmentDecisions

How much generating capacity is needed?

Optimal generating capacity for an electricity system is determinedby the willingness of consumers to pay for security of supply. Ifconsumers are willing to pay for an extra kilowatt of capacity morethan it costs to provide it, it is optimal to invest in this extrakilowatt. If it costs more to expand capacity than the valueconsumers attach to it, it is optimal to not invest. If neither morenor less investment is needed, then generating capacity is definedto be optimal and is said to be “adapted” to demand. Of course,there is no way of knowing a priori how much capacity would beneeded to have it adapted to demand. The real issue, however, iswhether markets — through price signals — will drive investmentto the optimal level.

Prices are the key determinant of investment decisions

Once competition is introduced into the electricity supply industry,the framework for undertaking investment decisions changesdramatically. Decision-making shifts from the state to investorsand risk bearing shifts from consumers to investors (as costs canno longer be automatically passed through to consumers). As aresult, investment decisions in a liberalised market are based onprofitability. Revenues depend on expected electricity prices whilecosts depend on the price (or cost) of capital. Thus, investmentdepends positively on the price of electricity and negatively on theprice of capital.

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Electricity prices must reflect the cost of producing electricity. Thisgenerally requires prices to fluctuate over time; for example, pricesshould increase during periods of peak demand when high marginalcost units must operate.The role of financial markets is to financeinvestments at prices (return on equity, bond interest rate, or loaninterest rate) which provide adequate returns, taking into accountthe risks of the investments. In setting an appropriate price, capitalmarkets need to forecast the return on the investment.The futureprice of electricity is a key element of this forecast. A muchdebated question is whether financial markets are able to forecastelectricity prices without bias.

There is concern that investors may be “myopic” basing decisionson current electricity prices alone. Myopic investment could resultin investment cycles as high electricity prices would induce invest-ment that would eventually depress electricity prices.This, in turn,could cause investment to halt. Over time, generating capacitycould become scarce, again raising electricity prices. These priceand investment cycles could be reinforced by the natural variationof electricity demand and prices over the business cycle.

The impact of competition

The main questions for policy-makers are whether any significantprice distortions can be expected in electricity and capital marketsand, if so, how the performance of these markets could beimproved in order to give the correct price signals to investors.These questions are analysed below. The main findings are thatdistortions can be expected to be small in a competitive marketand that a number of mitigating factors may generally reduce theirimpact.

Two main effects of liberalisation on electricity prices and the costof capital can generally be anticipated:

■ The average price of electricity will tend to decrease in aliberalised electricity market as costs are reflected moreaccurately.

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■ The cost of capital for generating capacity investments will tendto increase under competition, but the size of this effect maywell be small.As investors assume more risks the cost of capitalmay increase, but, on the other hand, risk-mitigating strategiesdo exist. As discussed below, investors can manage risksthrough a variety of contracts; and regulators can implementpolicies which will reduce the risk borne by investors.

The trend toward lower prices and higher cost of capital suggestsa gradual downward adjustment in the incentives to invest ingenerating capacity. However, this has to be seen in the context ofpast incentives to over-invest caused by high electricity prices,below-market cost of capital, or inadequate risk allocation. Thesecauses of excess capacity in the electricity supply industry (seeFigure 3) should disappear in the new competitive environmentand it may therefore be expected that a more efficient level ofcapacity will be achieved under competition.That said, the longevityof generation assets and the slow development of competitionsuggest that these changes may take some time to materialise.

In addition, electricity prices may decline slowly. Liberalisation ofelectricity markets does not happen overnight. Many OECDcountries are adopting a gradual approach to liberalisation. It is alsolikely to take time to establish effective competition in generation,which is often characterised by high seller concentration.The paceof reform depends much on a country’s starting point and therestructuring path it chooses to take.

It has also been suggested that investment may be more sensitiveto the business cycle in a liberalised market. However, the potentialsize of investment cycles is limited by a number of mitigating factors.In particular, the size of any potential impact is limited by themoderate electricity demand growth in most OECD countries, theshorter construction and lead times for some new power generatingtechnologies, and the increasing responsiveness of electricitydemand to price changes.

The following three sections analyse the issues of electricity prices,risk mitigation, and the business cycle in more detail.

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■ Electricity Prices and Markets

Prices in a perfectly competitive market

Prices must satisfy two essential conditions to induce optimalinvestment. First, average prices must at least equal the long runaverage cost of generating electricity. Lower prices cannot besustained because they would result in losses for electricitygenerators. Second, prices must equal the long run marginal cost ofgenerating electricity at each point of time. Lower prices imply thatgenerators would make a loss in at least some of their productionand consumers would pay some electricity below its cost. On theother hand, higher prices would inefficiently depress consumption.

If generating capacity is adapted to demand, a “perfectlycompetitive” electricity power market can be expected to yield anefficient outcome. Specifically, there would be full cost recovery.In addition, a perfectly competitive market is characterised byprices that are equal to short run marginal costs during off-peakdemand periods. However, if capacity is adapted to demand, priceshave to rise during peak demand hours reflecting that capacity isrelatively scarce. In equilibrium, prices must rise up to the pointwhere generators’ revenue equals their fixed investment cost plusvariable costs incurred during this period.Thus, even if generatorshave no market power, prices would rise to balance supply anddemand, thus reflecting long-term marginal costs.

Other market characteristics are helpful to induce optimal invest-ment: consumers are empowered to choose suppliers and clearlyunderstand what they wish and need to pay for; there is effectivecompetition among generators; and suppliers internalise the costsof long-term security of supply. This set of characteristics isextremely challenging to achieve. The following sections considersome of the barriers to an optimal investment.

Market concentration (Oligopoly)

Most OECD countries embarking on reform have a fairly concen-trated ownership of generation units.Concentration is also a feature

58


of many “reformed” countries. Market concentration may give riseto price distortions and, in particular, inefficiently high price levels.

Market power in electricity generation markets is not helpful tomaximising economic efficiency through lower costs, cost-reflective prices, and efficient investment. Higher electricity pricesincrease the profitability of investments and therefore generate astrong incentive to invest. From this perspective, oligopolisticbehaviour is benign. The challenge for policy makers is to ensurethat the incentives to invest result in actual investments beingmade. In particular, policy makers need to eliminate entry barriersfor new entrants and need to monitor market players to preventany anti-competitive behaviour that may discourage entry.

The problem needs to be addressed both in the early stages ofreform and subsequently, through market monitoring. In the earlystages of reform, the key policy issues that need to be addressedare barriers to market entry into generation, and the restructuringof existing generation activities, such as the unbundling of verticallyintegrated utilities. Conditions for effective competition ingeneration need to be established with particular attention paid tomid-peak load generation competition. Mid-peak load generatorshave a greater capacity to influence prices. Subsequently, carefulmonitoring of market players’ behaviour and strict enforcement ofgeneral competition law are necessary to prevent anti-competitiveand discriminatory behaviour (e.g., raising market entry barriers tonew entrants).

In conclusion, market concentration is not a threat to investmentitself as long as incumbent generators are not able to raise barriersto entry.Additionally, market concentration arises as a consequenceof ineffective liberalisation, rather than because liberalisation itselfis damaging to investment.

■ Investment and Risk Mitigation

The section on “Allocation of Risks” in Chapter 2 introduced thenotion of shifting risk in competitive markets and its potential

59


impact on the cost of capital. This section discusses the meansavailable to plant investors to minimise or mitigate increasedbusiness risks as competition is introduced and, consequently, toensure adequate access to capital for plant investments.

Greater risks are matched by greater potential rewards, notablyhigher profits. Higher profits may result from a variety of sources.First, under competition better management incentives generallyresult in lower costs. Second, subsidies to activities and groupsoutside the electricity supply industry — which are common insome regulated electricity supply industries — tend to disappearunder competition, thus increasing profits.Third, the developmentof new and more diversified services creates new profit oppor-tunities. And fourth, the possibility to enter new geographicalmarkets also creates new profit opportunities.

Greater potential rewards “automatically” mitigate the possiblygreater business risks, thus facilitating investment. The reason isthat, other things being equal, investors are generally willing to takemore risk in exchange for a higher potential payoff.

Financial instruments can provide risk-mitigating tools. Long-termcontracts between generators and consumers can potentiallyreduce risk premia for investments in generating capacity.The useof long-term contracts illustrates how consumer choice allowsconsumers to influence investment decisions and risks.

To some extent, all competitive power markets allow generatorsand consumers or power retailers to enter into long-termcontractual relationships. Most contracts currently take the formof forward contracts, option contracts, or power purchase agree-ments.The first two are sometimes described as financial contractsbecause they do not specify which plant will provide the power.Power purchase agreements are also termed “physical bilateralcontracts” because they specify the plant that will provide the power.

Forward contracts work in combination with a competitive spotmarket. They are one of the simplest forms of derivative instru-ments used to transfer, or “hedge” price risk. The parties agree

60


upon a price today (the so-called “strike” price), for “delivery” later.If the market price at delivery is higher than the strike price, theseller compensates the buyer. If it is lower, the buyer compensatesthe seller.There is a plethora of far more complex and advancedderivatives that can be used to hedge all kinds of price risk.

Option contracts have two prices, an option fee equivalent to acharge per kilowatt payable when the contract is signed, and anexercise price to be paid for each kilowatt-hour actually delivered.An option contract does not need the reference of a spot electricityprice to be implemented. Compared to forward contracts, optioncontracts are advantageous to the seller in that they partially hedgequantity risk.The option fee can also cover fixed generating costs.

Power purchase agreements are similar to the financial contractsdescribed above, but specify the plant that will provide the powerand therefore require the generator to be excluded from anycentralised pool. In countries with a mandatory electricity poolthese contracts are either restricted or banned.

A growing number of investors do not view the risk of investing ingenerating capacity as excessive. An increasing number of powerplants are developed as “merchant” plants. These are plantsplanned, built and operated without any type of long-termcontract. On the other hand, many US electric utilities, which havein the past been rated as ideal debtors by credit rating agencies dueto the predictable and stable revenue stream from captiveconsumers, have lost their “AAA” credit ratings as impendingcompetition threatens their consumer base. At this stage, it isdifficult to predict with certainty the stability and ultimateprofitability of individual firms or individual merchant plants.

In conclusion, various risk-mitigating strategies exist.While financialinstruments may not cover all risks completely, they do cover avery large element. In particular, consumer choice of supplierallows some investment risks to be ultimately borne by theconsumers. Moreover, a small but growing number of investors arewilling to risk investment in merchant plants, effectively “investingagainst a forecast” rather than investing against a contract.

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Apart from these risk-mitigating options available to companies,governments may introduce risk mitigating regulatory policies, suchas capacity payments in the spot market. These will be discussedlater in connection with electricity market performance.

■ Investment, Reserve Capacityand the Business Cycle

This section analyses the potential impact of investment cycles onreserve capacity margins and security of supply. The overallconclusion is that this impact is expected to be small.A number ofbuffers can absorb cyclical variations of investment activity withoutallowing security of supply to deteriorate. Finally, this sectionconsiders how some policy tools — capacity payments — can beused to further protect security of supply. However, these toolsgenerally have costly side effects.

Investment cycles?

Investment activity may go through cycles as a result of changes ina number of factors, including the cost of capital, expectations ondemand growth and future electricity prices, and the electricitysupply industry’s own financial position. All these variables mayaffect investment even in the absence of competition. However, itis likely that investment in a liberalised electricity supply industrywill be increasingly subject to the impact of business cycles as areother industries, particularly commodity industries. This impact islikely to be greater under competition because the large reservemargins common in non-liberalised electricity markets act as buffersagainst any temporary investment deficits. Also, governmentsupport of investments and monopolistic rights on electricity supplymay have reduced the exposure of the electricity supply industryto wider economic fluctuations.

As noted before, it is sometimes argued that investment fluctuationscould be even more pronounced due to myopic investor behaviour.This results in a tendency to concentrate investment in periods ofrelatively high electricity prices. In countries with access to well-

62


developed financial markets investors are likely to take intoaccount expected electricity prices over the whole life of thegenerating asset and thus not behave in this fashion. In any case, theactual performance of investment is essentially an empirical questionthat can only be totally settled on the basis of observation. Theevidence is presented below in the Section “Diversity of Input Fuels.”

How would security of supply be affected by investmentcycles?

If there is no significant excess capacity, fluctuating investmentactivity may result in periods of reduced reserve margins.The lessprice-elastic are electricity demand and electricity supply, the longermight be the temporary imbalances caused by business cycles, andthe greater the price increases would have to be to trigger newinvestment or prompt consumers to reduce consumption to copewith a capacity shortage.

In addition, it is sometimes suggested that investment in reservecapacity may be inadequate under competition at every point alongthe cycle. In particular, reserve equipment expected to run onlyexceptionally due to a lack of demand for its output may be adifficult investment as payments will be intermittent and unpredict-able.The result could be a sub-optimal level of reserve capacity.

How plausible is either scenario? Several factors suggest that, inpractice, competitive power markets should cope with unforeseendemand growth in a number of ways without jeopardising securityof supply.

First, new technologies are shortening lead and construction timesfor generating capacity, thus effectively increasing the priceelasticity of electricity supply. Electricity supply has traditionallyshown low price elasticities, at least in the short- and medium-term. The long lead and construction times of base load powergenerating capacity observed in the past pointed towardcomparatively low supply elasticities.The current trend is to investin combined-cycle gas turbines, which, in addition to having low

63


capital cost, can be manufactured on assembly lines, shipped to thesite by train, and installed in less than two years. In contrast, typicallead time for coal-fired plants is around five years, and nuclearplants take roughly seven years to build, provided the process runssmoothly.

Second, the trend towards repowering generating plants is alsoshortening investment lags. Investors find it less risky and moreprofitable to buy an existing, even if the plant is not profitable, andto refurbish by substituting or adding a single or combined-cyclegas turbine for the old steam boiler. Since most of the existingfacilities can be re-powered, total investment costs can be reducedand construction times significantly shortened.

Third, peak load pricing reduces the amount of reserve marginneeded by “shaving” off the peaks of demand. Electricity consump-tion is becoming more price-sensitive with the introduction oftime-of-use or peak-load pricing schemes. So far, peak-load pricingmechanisms have proved effective in smoothing out demand byshifting demand from peak periods, which are charged a higherprice, into non-peak periods, which are charged a lower price.Traditional measurements of electricity demand elasticities thatconsistently rendered small estimates may be all but irrelevant inthis context. These measurements, necessarily based on historicdata, and carried out for electrical demand over several years oreven decades, fail to capture the consumer’s reaction to time-of-use pricing.The reason is that these pricing policies did not exist atthe time when the elasticities were measured.

Fourth, power demand grows in a comparatively slow and steadyway in most OECD countries, and there are no large year-on-yeardemand swings.This reduces the scope for unforeseen imbalancesbetween generating capacity and electricity demand.

Fifth, increased regionalisation of electricity may enable individualcountries to live with reduced national reserve margins.The creationof the EU internal electricity market is an example of this regional-isation through minimisation of national market entry barriers.

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Capacity payments

If, in spite of the above arguments, there is concern about a cyclicaldeterioration of reserve margins, there are policy tools available.Tocounter this potential problem, some electricity pools use capacitypayments to decrease the risk faced by generators and to induceinvestment in reserve capacity.These markets not only remuneratethe electrical energy, i.e., kilowatt-hours generated, but also theestablished generating capacity which can be drawn upon in anemergency. This capacity is remunerated separately, provided thegenerator declares it available for potential production.

In some competitive power markets, notably in the UnitedKingdom, this capacity payment is related to the probability that asupply shortfall might occur (the Loss-of-Load Probability, LOLP),and to a theoretical measure of the damage such a shortfall wouldcause to the consumers (the Value of Lost Load,VOLL). Capacitypayments are currently provided in the United Kingdom, althoughthere are plans to abandon them there, Spain and Argentina.Thereare no capacity payments in the Australian national power marketor NordPool.

There is no consensus at this stage on whether a capacity shortfallis a real risk and, if so, whether capacity payments are the correcttool to support investment. Some of the literature assumes thatwithout capacity payments, the level of reserve capacity providedby the market would be suboptimal. However, many othersdisagree on the basis that consumers may be expected, in a fullyliberalised market, to demand and pay for reserve capacity, and thatsuch a market will put a monetary value on reserve capacity.

It is important to note that capacity payments are not a free policy.They generate significant market distortions, at least in markets inwhich some generators enjoy market power, and generators’behaviour may be distorted by capacity payments. In the short run,there may be incentives to manipulate the availability of plants toincrease revenue and profits. In the long run, depending on theirsize, capacity payments may induce over investment in generating

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capacity.Additionally, capacity payments may interfere with efficientmarket design: in particular, they are difficult to handle if bilateralcontracts outside the pool are allowed. In sum, capacity payments,in seeking to fix one possible problem of potentially sub-optimalreserve capacity, may create another problem, namely economicinefficiency. Overall, it can be argued that attempts to “put back in”artificially what the market may fail to provide will hinder, ratherthan help, the evolution of an effective and efficient market.

However, there is currently excess generating capacity in manyOECD countries (see Table 5) and so the issue of adequate reservemargin is, for the foreseeable future, not a practical concern.

■ Transition Issues: Minimising Regulatory Risk

The transition from heavily regulated to open electricity marketsoften involves significant uncertainties.The end point of reform isnot always clearly defined and, even if it is, learning by doing revealsoptions for improvement.The first wave of reforms developed inthe United Kingdom and Argentina, among others, has given way toa second wave of reforms in these same countries in whichsubstantial aspects of the regulation are being reformulated.

In addition, reform proceeds gradually in some countries. Thetiming of successive partial reforms may not be known. Also,implicit in the implementation of a gradual reform program, tworegulatory systems are set to coexist, the old more heavily regulatedregime and the new market oriented regime. The boundariesbetween two different regulatory are often fuzzy.As a result, thereare disputes and the application of rules remains uncertain causingconsiderable regulatory risk in the transition to competitiveelectricity markets.

Regulatory risk, like other risks, may have the effect of discouraginginvestment and increasing the risk premium required by investors.While this is a transitional problem, it may be significant, especiallywhere additional investment is needed at the time of opening themarket to competition. Governments have a key role in minimising

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regulatory risk by providing a credible and clearly definedregulatory framework for electricity markets to facilitateinvestment.

■ Diversity of Input Fuels

Another fundamental security of supply issue is the diversity ofinput fuels to power generation. Other factors being equal, greaterdiversity tends to decrease the electricity supply industry’s vulner-ability to price increases in input fuels.The importance attached todiversity varies from country to country, depending on the extentto which a country has indigenous fuel sources and other factors.For example, Switzerland and Norway have chosen low diversity intheir power systems because of the abundant availability of hydropower.

It is, therefore, difficult to generalise about the implications ofcompetition on input fuel diversity. However, it is worth noting thatdiversity may be an issue and, if this is the case, governmentmonitoring of investment developments may be appropriate. Forinstance, the current competitiveness of natural gas in combinedcycle gas turbines may make some countries more reliant onimported fuels and more exposed to changes in natural gas prices.However, the trend toward investment in gas-fired generation mayincrease diversity, at least initially, as gas is introduced in theportfolio of input fuels and the long lifetimes of many power plantsimply that fuel substitution occurs slowly.

To the extent that input fuel diversity is an issue for particularcountries, it is important to ensure that markets integrate thevalue of diversity into the price of electricity. Supply contractsincorporating clearly defined supply obligations and penalties fornon delivery would influence investment decisions by generators,thus effectively internalising the value of security. Alternatively,regulatory measures (e.g., obligations to buy electricity producedfrom certain sources) can be implemented to influence fuel choicesin a competitive market.

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■ Empirical Evidence

Comprehensive empirical evidence that could be used to compareinvestment before and after the introduction of competition inelectricity does not yet exist. The majority of liberalised powermarkets started out with a fair amount of over capacity (see Table 5),which acts as a buffer against any problems, at least in the short tomedium term. A possible example is Argentina, which was liber-alised in 1992 with a considerable need of capacity investment, andwhere investors (mainly foreign) have invested US$ 4 billion in themeantime, mainly in fossil-fired capacity.

Since electricity does not provide much useful empirical evidenceyet, it is interesting to look at other recently liberalised marketsthat share some of electricity’s special characteristics. Insight maybe gained from the experience of airline and telecommunicationsmarket liberalisation.

Air transportation

Air transportation shares some of the characteristics of electricity:they deliver a non-storable service; are subject to a peak loadproblem; are capital intensive; and show some network character-istics through their use of airport infrastructure dispersed in space,although this latter feature is much weaker than in electricity, gasor telecommunications. The US airline industry was liberalised in1978, providing nearly two decades of experience with liberalisationin this industry.The following observations can be made:

■ The airline industry entered competition with a very large overcapacity.As a consequence, load factors on domestic trunk linesfell from 70% in 1956 to a mere 48% in 1970.After liberalisationload factors rose again to above 60% and there was enormousservice expansion. Despite occasional phenomena like over-booking and delays, service has doubled, frequency hasincreased, and a much larger number of citizens have air travelaccess from nearby airports than before liberalisation.

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■ Prices came down considerably, in some cases dramatically, dueto price wars caused by new entry in the early years.Alongsidelower prices, intense price differentiation now dominates theindustry.

■ There was massive entry in the early years. But of 18 major newentrants between 1979 and 1985, only two had survived by 1988.The overwhelming majority of the others had gone bankrupt.This resulted in a “boom-and-bust” cycle, involved tremendousmerger and takeover activity, and led to the accumulation oflarge debt.

■ The fleet of aircraft is on average older than it was beforeliberalisation, and is the “oldest and most re-painted fleet ofaircraft in the developed world” (Dempsey, 1992).

■ However, and most importantly, despite the somewhat messyintroduction of competition, some troublesome market out-comes and the huge demand growth and resulting air spacecongestion, safety (which might be equated to supply security inthe electricity context) had not deteriorated.

Telecommunications

The telecommunications sector also allows an interestingcomparison due to its service character, and peak-load and networkcharacteristics.The following concentrates on the traditional, fixed-link telephony market in the United Kingdom and the United States,which were two of the earliest to liberalise their markets. Thefollowing observations can be made:

■ Investment appears to be abundant, but this might not allow anydirect conclusion for electricity competition since competitionin telecommunications has in recent years been partly causedby technological change, which has so far played a much smallerrole in electricity.

■ Prices have declined slightly and pricing has become much morecomplex, as in the airline industry. Also, dramatic re-balancingbetween long-distance and local tariffs has taken place. Long-

69


distance calls became much cheaper compared to local calls,reflecting efficient removal of cross subsidies. Fixed chargeshave increased, whereas usage charges (charges per telephonecall) have come down. The overall effect is a slight decline in(real) total prices for residential consumers and a slightly largerreduction for business consumers.

■ The ranking of the United States and the United Kingdom ininternational service indicator comparisons provides clues as tothe performance of competitive markets.The United Kingdomand the United States are among the seven countries with thelowest call failure rates in the OECD.The United States has thelowest, the United Kingdom the second-lowest number of faultsper 100 lines and per year in the OECD.

To summarise, these experiences in airlines and telecommuni-cations suggest that:

■ Prices decline, but also become much more complex incompetitive markets.

■ Liberalised markets continue to meet or even improve on non-price objectives, such as service quality and safety.

■ Investment levels remain adequate.

Conclusions

Investment continues in competitive markets. Incentives to investin liberalised electricity markets are provided by profit opportunitiesas in any other liberalised market. Risk and macroeconomicfluctuations may have a larger impact on investment in competitivemarkets but mechanisms exist to deal with them.

In the long run, the large reserve margins often observed in thepast may tend to disappear. Under competition there are noincentives to build excess capacity; this is a good thing in that itreflects a more efficient outcome than in the past; however, theevolution of reserve margins also depends upon the particular

70


policies such as capacity payments adopted by each country. Inpractice, changes in reserve margins can be expected to proceedslowly in most countries due to the combination of a gradual policyapproach and a continuing relatively concentrated market structure.

Is there a role for governments?

Governments still have an important role in the new environmentand the following actions may help to mitigate potential problems:

■ Ensure as far as possible that an effective market, includingeffective competition in generation and effective end user choiceis established.Address market entry barriers to generation.

■ Monitor the market structure and possible anti-competitivebehaviour of market participants to sustain effective entry intothe market and effective consumer choice.

■ Establish well-funded, well-staffed and competent regulatorsand anti-trust enforcement agencies to prevent the emergenceof barriers to new generation entry.

■ Monitor system reliability and investment in generation.However, unless the monitoring indicates real problems,governments should refrain from interfering. The monitoringneeds to be adapted to the size of the market. In some cases, itmight have to be done at international level, in others atnational or sub-national level.

■ Monitor input fuel diversity, estimate the extent to whichsecurity of supply is ensured by the market. If remedial action isneeded, measures at economy-wide or energy market level arepotentially more effective. Measures restricted to the electricitymarket are a second-best solution as they ignore alternativefuel uses. If they are the only feasible solution, they should bemarket-based.

■ Create a favourable investment climate by providing a credibleand clear regulatory framework and streamlining the adminis-trative process for construction permits as far as possible

71


without jeopardising other important regulatory concerns (e.g.,compliance with safety and environmental regulations). ManyOECD countries have cumbersome, lengthy procedures thatconsiderably lengthen lead times.

72


APPENDIX:ENERGY INVESTMENT1

Joint Paper by the Energy CharterSecretariat and the International EnergyAgency2 presented to the G8 EnergyMinisterial in Moscow, 1 April 1998

Executive Summary

All countries will need to assure a supportive climate forinvestment to meet their energy needs, enhanceefficiency and improve environmental quality. Energyinvestment requirements will amount to 3 or 4% ofworld GDP over the next two decades. As a percent ofGDP, the needs will be higher still in the transitioneconomies, because of the need to replace or moderniseobsolete and inefficient plants and infrastructure.

There is no shortage of capital for global energyinvestment — the problem lies in how to mobilise it.Energy projects will be in competition with other invest-ment opportunities in both domestic and internationalmarkets.

Investments in the energy sector provide a range of socio-economic benefits in the regions and countries wherethey are made.These include job creation, increased taxrevenues and competitiveness, as well as infrastructure,transfer of modern technology and managerial techniques,improved efficiency and the ability to reallocate govern-ment spending.

73

appendix: energy investment

Growing needfor energyinvestment

1.This is an abridged version of the paper. References specific to the Russian energy sector havebeen eliminated.2.This paper, presented to the G8 Energy Ministerial in Moscow, 1 April 1998 was jointly preparedby Leif K. Ervik and Lise Weis of the Energy Charter Secretariat and Hans G. Kausch and IsabelMurray of the International Energy Agency.

Investmentcompetition

Socio-economicbenefits

Countries’ ability to mobilise enough capital for theirenergy investment needs will depend on the quality oftheir investment, fiscal and regulatory policies. This inturn will crucially affect the rate of economic growth andliving standards in those countries.

One of the most important considerations for potentialinvestors will be a country’s political and economicstability. Companies will also evaluate other market,financial and legal risks. The main areas will be marketaccess, including market structure, discrimination andbureaucracy and market operation, including the legalframework, the financial environment and marketconditions.

Companies will want to know that they can obtain anyconsent needed for new investments through proceduresbased on clear and consistent criteria and avoid bureau-cratic complexities and delays. Foreign investors will beparticularly deterred if there is discrimination on nationalitygrounds.

Traditionally, in many countries, the scope for privatesector activity in the energy field has been limited by theinvolvement of government and State enterprises.Thereis now widespread recognition that liberalisation, includingprivatisations and reduction of monopolies yields majorbenefits for the efficient operation of energy markets.Governments need to ensure fair competition, includingcontrol of monopoly behaviour, and avoid distortions inenergy prices.

Companies will always look closely at the overall legaland administrative framework in a particular country.They want to be sure that they can, if necessary, protecttheir investments by recourse to law.This matters mostin cases where agreements they have entered into are notbeing complied with by other parties,or where customers

74

Meeting energyinvestment needs

depends oncompetitiveness


Thoroughassessmentof market,

financial andlegal risks

Excessivebureaucracy ordiscrimination

hindermarket access

Attractivemarket

structure

A stable andeffective legal

environment

have defaulted on payments. Dispute resolution is animportant aspect of this issue, including whenevernecessary access to international arbitration. In a widersense companies will want to feel protected againstcrime and corruption.

In countries where appropriate legal and/or fiscal regimesare still being developed or have not long been in place,governments will need to take positive action to createinvestor confidence through strong and stable legalguarantees. International treaties can provide a broadly-based, secure and stable foundation for large-scaleinvestments with long pay-back periods. Examples are theEnergy Charter Treaty (ECT) and its future extensions,bilateral investment treaties and production sharingagreements in upstream oil and gas investments.

The viability of an energy investment will depend cruciallyon the relevant tax regime. Experience has shown thatan unstable or unbalanced tax system can be the singlemost important factor in deterring investors. This hasbeen particularly true where taxation is based on grossrevenues rather than on profits, with allowance forincurred costs. A system which favours short-termgovernment revenues can jeopardise long-term invest-ment benefits.

Companies will want to know whether they can movetheir future production to domestic or internationalmarkets.They will ask for secure access on fair terms tolocal and national energy transport systems, such aspipeline networks or electricity grids. They will also besensitive to any likely restrictions on their ability toexport or import energy, or on their purchases of energyequipment or services from abroad. A regime whichfollows World Trade Organization Rules will providecompanies with considerable assurance in this regard.

75


Pattern oflegal and fiscalstabilityis needed

Proper taxationrules

Access to energytransport systemsand trade

Governments should ensure that attention is also givento investments in energy efficiency and in energy-relatedenvironmental projects, along with investments in energysupply.

G8 Energy Ministers are invited to widen awareness ofthe importance of energy investments for worldeconomic growth and trade by bringing the conclusions,and recommendations based on this paper to the attentionof other governments. Proposed Recommendations onEnergy Investment are found at the end of this paper.

Introduction

This paper assesses future energy investment needs andthe benefits which national economies can gain fromprivate sector energy investments. It identifies the policiesneeded to attract private sector investment, whetherdomestic or foreign.This paper draws on valuable studiescarried out by or under the auspices of the World Bank andthe European Bank for Reconstruction and Development.

Energy Investment Needs andBenefits

■ Energy Investment Needs

Projections of energy investment needs depend to a largeextent on projections of supply and demand. TheInternational Energy Agency’s “World Energy Outlook”indicates that, in the absence of new policies to curbenergy use, world energy demand will grow by 66%between 1995-2020. Fossil fuels are expected to provide95% of additional global energy demand to 2020. Theglobal distribution of world energy demand will changesignificantly, with developing countries more thandoubling their energy consumption by 2020.

76

Energyefficiency and

the environment


Specificrecommendations

to governments

World energydemand to growby 66% between

1995-2020

Energy forecasts in developing countries and transitioneconomies are particularly uncertain with respect to thetiming and rate of economic growth.There is also uncer-tainty about the relation between economic growth andenergy demand, given the recent radical changes ineconomic structure and systems. Energy data in thesecountries is much less detailed and less reliable than inOECD countries. The timing of economic recovery andthe rate of growth in GDP and energy demand will beinfluenced by investment patterns which in turn willdepend on appropriate framework conditions. Environ-mental policies also exacerbate the uncertainty of globalenergy demand and supply projections; they areincreasingly creating new energy related investmentneeds.

The World Energy Council (WEC) recently completed astudy on global energy investment needs (based ondemand and supply projections similar to those of theIEA). WEC concluded that annual investment require-ments to 2020 will remain basically unchanged at about3% to 4% of world GDP. Financing requirements vary byregion depending on the level of economic development,industrialisation, motorisation, etc. The divergence inneeds is especially great in the case of transitioneconomies, where investment needs are almost 10 timesthose of OECD countries in terms of share of GDP.Thisdifference is a function of their current low GDP levelscombined with the need to invest to upgrade and renewold, badly maintained and inefficient infrastructure andtechnology.

Despite varying estimates of the level of investmentneeds, most studies conclude that there will be noshortage of capital resources to meet these needs. Theproblem is how to mobilise that available capital intoinvestments in energy infrastructure.

77


Uncertaintyas to the timingof economicrecoveryis dependenton stable/competitiveinvestmentenvironment

Global energyinvestmentneeds varyby region

There is noshortageof capital... but it needsto be mobilised


Energyinvestments

competeinternationallyacross sectors

Energy investment projects compete with other invest-ment opportunities across the domestic economy andinternationally as well. In the area of new powergeneration capacity alone, the World Bank estimates thatAsia would require about $30 billion/year and LatinAmerica about $15 billion/year and estimates the gapbetween savings and investment needs by 2005 at about$50 billion/year in both Asia and Latin America. In Russiaand Eastern Europe the World Bank estimates this gap atabout $10-15 billion/year. The crux of the issue iswhether these countries will be able to attract enoughprivate domestic and/or foreign investment to meet theirenergy needs.

Average Annual Investment Requirementsby Fuel and Region: 1990-2020

1990

US$

Bill

ion

0

100

200

300

ElectricityCoalGasOil

OECDDeveloping CountriesTransition Economies

7%-9% of GDP

3%-4% of GDP 0.8%-1.1% of GDP

Based on WEC Case B "Middle Course", which projects more coal and nuclear based electricitygeneration in OECD countries than IEA projections, which assume much more gas-based newcapacity.WEC estimates of cost of new power capacity in OECD countries are therefore higherthan those of the IEA.

Investment needsin transition

economies arealmost 10 timesthose of OECD

countries as apercent of GDP

78

Foreign direct investment acts as a supplement to domesticsavings.The chart below compares the different levels offoreign direct investment inflows over the last 15 years inthe United States, China and Russia. The United Statesattracts more foreign investment than any other country;US companies are also actively investing abroad andgiving the United States its position as the largest sourceof foreign direct investment. Since 1990,China has createdan investment environment which is increasingly attractingforeign direct investment to promote and help sustain itshigh GDP growth rates (in double digits by some esti-mates). The comparison between Russia and China isstriking, with China attracting over $42 billion in 1996compared to less than $2 billion in Russia. (In 1997,preliminary estimates show foreign direct investment toChina and Russia at $32 billion and $3 billion, respectively).

79


Foreign directinvestment actsas a supplement

Foreign Direct Investment* Inflow Comparison($US billion)

US$

Bill

ion

0

15

30

45

60

75

90

RussiaChinaUS

1996199519941993199219911990

*Poland/Hungary/Czech Republic combined attracted foreign direct investment in the order of$8.5 billion in 1996.

■ Investments in the Oil and Gas Sectors

The upstream oil and gas business is dominated by theprivate sector. Both large multinational oil companies andthousands of small to medium size companies competeto replace reserves at the lowest possible cost. Since1983, global oil demand has increased at a rate of about1.5%/year, and at 2.5% since 1995. The IEA projects oildemand to grow at an annual average rate of 1.8% to 2020.

In 1996, global investments in the upstream oil and gassector reached about $80 billion. In recent years, theindustry has focused on cost reduction through advancedcomputer and engineering technology as well as thestreamlining of company structure, both trends beingdriven by relatively low oil prices. Recently, investment inthis sector has been increasing as companies have beenforced to drill in deeper waters and in more technicallydifficult environments. Constraints are being felt on theservice and equipment pool, as the large capital stockbuilt in the period of higher oil prices reaches fullutilisation. On the other hand, although day rates for oilrigs have increased significantly, that rise has been some-what counterbalanced by improved technologies whichhave led to a net decrease in finding and production costs.

Most upstream oil and gas investment is financed directlyby the large multinational oil companies or by fundsborrowed by the private sector. Ultimately, the investor’swillingness to commit resources depends on a project’sability to meet the return expectations of shareholdersand lenders. Banks usually base their project loans on theprofitability of and control over assets/production andneed to have confidence in the investor to operate andfund its share.They normally require a significant commit-ment of an investor’s own resources. This requires thatthe private investors’ expectation on the return meet therisks of the project.

80

The upstream oiland gas business

in most partsof the world

is dominated bythe private sector


In 1996, globalinvestments in

the upstream oiland gas sectorreached about

$80 billion

Most upstreamoil and gas

investmentsis financed

ultimately byshareholdersand lenders

Over the last decade, there has been a marked increasein areas open for petroleum exploration and develop-ment. New prospects exist in Asia, Africa, Latin Americaand in Central Asia and Transcaucasia. Even a number ofOPEC countries, facing shortages of capital and needingmore advanced technical know-how, have begun to seekforeign investors in order to raise future productioncapacity. IEA analysis has shown that North Africancountries (Algeria, Egypt and Libya) have been successfulin attracting foreign investment by improving their fiscalterms for oil and gas development. They have offeredcompanies potentially greater profits while sharing therisks associated with hydrocarbon development. Similardevelopments can be observed in some countries of theMiddle East and in particular in the new oil and gasproducing countries in Central Asia and Transcaucasia.Competition for private investments has increased, asinternational oil companies assess the risks and returnsavailable in each country.

The United States has a significant level of foreign directinvestment in its oil sector (especially through BritishPetroleum and Royal Dutch/Shell). BP is, indeed, thelargest oil producer in the United States. Norwegian oilpolicy is based on a combination of government controland a market system which allows companies to developthe most profitable and efficient solutions. Norwegiancompanies have entered into co-operation agreementswith foreign companies which have helped them to staycompetitive and maintain a high level of technical know-how. On average, foreign participation in Norwegian oilproduction between 1971 and 1994 was 38%.

The Russian economy as a whole requires a major infusionof capital. So far, however, the experience of investors inthe Russian upstream oil sector has not been conduciveto further investment, either domestic or foreign. As

81


Competitionfor privateinvestmenthas increased

Experiencein the USand Norway

Experience ofinvestors in theRussian upstreamoil sector has not

shown in the graph below, Russia’s annual investmentneeds are estimated at a minimum of $5 to $7 billion anda maximum of $9 to $13 billion.

Unstable and unbalanced legal, fiscal and regulatoryconditions also create strong disincentives for portfolioinvestment. Basic problems still exist in the overallstructure and regulation of the stock market, but alsowith respect to principles of corporate governance, lackof transparency and insider shareholding.

82

Russian companies’

ability to mobilise

capital will be

limited until macro

economic and

market framework

conditions are

in place


Russian Oil Production and ExportsHistory and Forecast Dependent on Investment

Mill

ion

Tonn

es

0

100

200

300

400

500

600

201020052000199719961994199219901988

Exports

A

C

B

Forecast

* Source: New Energy Policy of Russia, Mintopenergo, 1995

Estimates of global investment needs in the gas sector to2020 range from a low of $900 billion to a high of$2.6 trillion. Investment needs for natural gas face muchthe same situation as those for oil. Both require large

A - Maximum Case with Investment needs: $9.5-13 Billion/yB - Minimum Case with Investment needs: $5-7 Billion/yC - Possible Case with no new Investment

Production with foreign Investment

Investment needsfor natural gas

are much thesame as for oil

been conducive tofurther investment

Russian oil supply

down 50% ...

The decline

could resume

unless there are

significant

investments

upfront capital investments and often long term payouts.The transport of gas through pipelines or via LNGfacilities is a critical part of investments. In a significantrecent development, GazProm has been able to borrow$2.5 billion from a consortium of 57 international banksto help finance the world’s largest gas transport project.

IEA projects world gas demand to double by 2020 withmuch of that increase forecast in the CIS and developingcountries. Meeting such increases in demand will bechallenging and will require particularly suitable investmentconditions especially for capital-intensive distributionnetworks, pipelines or LNG plants.

■ Investments in the Coal Sector

Annual global investment needs for coal, the second mostused primary fuel after oil, are estimated by the WEC at$13 billion. Investment in coal is financed by privatecompanies in the key coal export countries. Potentialfinancing problems relate to the restructuring necessaryin many markets, including the closure of uneconomicmines (at least 100 of 250 mines in Russia). There mayalso be a need for investment in coal import facilities. Inaddition, investment is necessary to rehabilitate thoseremaining mines which have prospects of achievinginternational competitiveness. In all producing countriescontinuing investments are necessary to lower costs andincrease labour productivity.

Increasingly, investments related to environmentalaspects of coal use and production will be needed.This isalso the case in China and India, where more advancedtechnology and efficient use will be a focus of investmentneeds; more than 50% of these two countries’ projectedincreased energy needs will be met by coal.

83


Need for stable,transparentframework

Potentialfinancingproblems relateto restructuring

Increasingly,environmentalrelatedinvestmentswill be needed

■ Investment in the Electricity Sector

Electricity is the fastest growing energy sector and thebiggest challenge for financing in the future. The powersector is the most capital intensive and the scale of itsinvestment needs is greatest. The IEA projects globalrequirements for new power capacity over the period1995-2020 at some 3475 GW, about half of which isprojected for China and the other developing countriesand a third is required in OECD countries.Total invest-ment needs to meet this projection are estimated at$3.3 trillion (1990 dollars). As a percentage of GDP,investment needs are highest in the transition economies.

84

Electricity sectorrepresents the

biggest financingchallenge


Capital expenditures on new generating plant(billion $US, 1990 values)

% of GDP

1995-2000 2000-10 2010-20 1995-20 1995-2020

OECD Europe 76 117 174 367 0.16%

OECD N.Am. 54 99 155 308 0.14%

OECD Pacific 45 149 180 375 0.41%

FSU/ECE 25 153 210 388 0.75%

China 97 253 385 735 0.37%

Rest of World 167 409 509 1085 0.31%

World 463 1181 1613 3257

% of GDP 0.28% 0.28% 0.29% 0.28%

In many countries due to the structure of the electricpower industry and to government tariff policies powergeneration projects have relatively low rates of return.Frequently significant government subsidies are grantedto maintain artificially low electricity prices. Under these

In many countries,the electric powerindustry does not

operate profitably

conditions, private investors have been reluctant to enterthese countries, and most investment has been financedby governments.

Strained public resources cannot cope with loomingelectricity capacity needs especially in developingcountries where increases in demand are greatest. Theneed for power sector financing, along with a desire toincrease economic efficiency has led many countries toseek private sector involvement in electricity supplysystems.This corresponds with a world-wide trend in theelectricity sector toward privatisation, deregulation, andcommoditization and an increased focus on privatesector financing. Private sector involvement brings notonly financing, but also market-oriented managementskills, access to the latest technology, and usually quickerimplementation than would be the case under publicsector management. Private investment may also allowgovernments to redirect public funds to other needs.

Governments are turning increasingly to private sourcesof investment through Independent Power Producers(IPPs) or even the introduction of competitive generationmarkets. In the case of IPPs, power purchase agreementseffectively commit distributors to purchase electricity atcost-based prices over a long-term period. Powerpurchase agreements are a basis on which IPPs can obtainfinancing. Success of IPPs could be enhanced through theimplementation of basic “best practice” principles likethose put forward by the Asia-Pacific Economic Co-operation (APEC) in 1997. This document deals withbasic investor needs such as transparency, predictabilityand reduction of risk. It encourages competition ininstitutional and regulatory structures, tender/bidprocesses and evaluation criteria, power purchaseagreements and associated tariff structures, as well asclear taxation and foreign exchange regimes.

85


The situation isslowly changingwith a focusmore onprivate sectorinvolvement

Governmentsare turningincreasingly toprivate sourcesof investment

In transition economies, investments in the electricitysector are of primary importance; inadequate invest-ments could seriously hamper economic growth.However, the structure of tariffs is a major barrier toinvestment, as some industries are charged higher thannormal rates in order to cross-subsidise households andother industries that cannot pay. Changing such policies isa sensitive and politically charged undertaking. In Russia,much progress has already been made. The FederalEnergy Commission has strengthened its control ofelectricity tariff setting and methodology. The UnitedEnergy Systems (UES) has increased transparency and isphasing out cross subsidies, thus laying the basis forcompetition in this sector. Independent generators couldusefully start investing and competing in this sector if UESmanages to transform itself into solely a power trans-mission and distribution company. Such a developmentwould allow generators to compete and sell to thetransmission grid directly or transport electricity throughit to regional energy companies.

Nuclear power is one among other possible choices ofgeneration plant. A number of countries, particularly inAsia, have firm plans for new nuclear projects. However,few other opportunities for new nuclear plantconstruction are seen in the near term, because there area number of long-term issues that must first be resolved,notably waste disposal and non-proliferation. In manymarkets around the world nuclear power is notdemonstrably the least-cost alternative, when all relevantcosts for the fuel cycle and safe generation plants aretaken into account. There is increasing internationalconcern about projects to upgrade plant safety and toextend plant life and whether they will ensure thatinternational levels of safety are upheld. This is nowbecoming a concern in transition economies where suchinvestments are being made.

86

In transitioneconomies

inadequateinvestments

could seriouslyhamper

economicgrowth


Fewopportunities

for newnuclear plant

construction inthe near term

if a numberof long-term

issues arenot resolved

■ Investments in Energy Efficiencyand Environment

Concerns about climate change and other environmentalconsequences of the production and use of energy focusattention throughout the world on energy efficiency.Various international fora, most notably the Conferenceof Parties under the United Nations FrameworkConvention on Climate Change (UNFCCC), emphasisethe need to promote and implement actions thatenhance energy efficiency and limit greenhouse gasemissions. The forthcoming Ministerial Conference“Environment for Europe” under the auspices of theUN/ECE and with support from the IEA and the EnergyCharter Secretariat, is expected to adopt guidelines,strategies and policies to improve energy efficiency andinternational collaboration.

Energy intensity levels in transition economies are muchabove OECD levels, even those of 25 years ago. IEAindicators show Russian space heating requirements 50%greater than in Nordic countries (adjusted for climateand house size). Manufacturing energy use per tonne ofoutput is up to twice the level in western Europeancountries. Energy intensity has actually increased in theFSU since 1990.This underlines the urgency of increasedinvestments in energy efficiency in these countries.

There is evidence that energy could be more efficientlyused in all economies. Estimates suggest a potential forcost-effective energy savings in the range of 10%-30%over the next two to three decades.The energy efficiencypotential in transition economies is higher, given thatthese countries were shielded from the energy priceshocks of the 1970s that triggered much of the energysavings in OECD countries. At current domestic energyprices the potential for energy savings in Russia isprobably in the range of 40-45%.

87


Energyintensity levelsin transitioneconomies aremuch abovethe OECD’s,even thoseof 25 years ago

The world-widefocuson energyefficiencyis increasing

The energyefficiencypotentialin transitioneconomiesis higherthan in OECDcountries

Energy efficiency investments can be profitable, aswitnessed by increasing Energy Service Company(ESCO) activity in some countries.They are imperative ifindustry is to remain competitive and provide gains inpersonal comfort and standards of living. The EuropeanCommission, EBRD and others have estimated themarket for energy efficiency projects in the CIS andCentral and Eastern Europe at $40 billion with a pay-backof less than three years.To date the level of investment isless than a tenth of needs.

Major investment barriers exist, not the least of thembeing the focus of multilateral development banks,commercial banks, and large investors in transitioneconomies on supply-side investments. In part this is dueto the small size of energy efficiency projects (making thefixed costs of arranging loans prohibitive) and to the lackof trained and skilled experts to develop bankableproject proposals.On a macro-economic level barriers toinvestment include subsidised energy and heating prices,lack of enforceability of contracts, unstable investmentenvironments and non-payment of energy bills. Barriersof a more structural/ technological nature compound theproblem. These include lack of metering, the very

88

Potential energyefficiency

investment inthe CIS andCentral and

Eastern Europeis estimated at

$40 billion with apay-back of lessthan three years


Comparative Energy Intensity Levels

TOE/

000s

of U

S$/P

PPs

(199

0)

0

0,5

1

19961981

OECDCEEFSU

0.7

1.01

0.5850.52

0.307 0.267

* Source: IEA

Major investmentbarriers exist

relatedto demand-sideenergy projects

structure of building and district heat supply systems andthe uncertain future of many energy-intensive industries.The social changes in transition economies are alsomaking implementation of energy efficiency projects atthe residential level difficult, due to a lack of homeownerresponsibility or housing associations.

Considerations of health, safety and environment willincreasingly become a high priority for governments,private investors and the public at large.This will imposean even greater financial burden on transition economies,where past energy-related investments were undertakenwithout due consideration of the environment. Pollutedareas posing serious human health risks will increasinglybe made priorities for remediation. But lack of market-based mechanisms remains a key problem in accuratelyaddressing environmental problems. Projects andactivities under the UNFCCC have the potential forintroducing an extensive amount of foreign directinvestment.

■ Benefits from Investmentsin the Energy Sector

Several studies show how energy investments provide arange of socio-economic benefits from improvements ininfrastructure to transfer of technology, job creation,increased tax revenues and industrial and labourcompetitiveness. In general private investment allows thegovernment to redirect its funds to other uses and publicneeds; i.e., into areas which will not attract privateinvestment. By creating more private-sector employ-ment, the tax base is widened and there is a reduction inthe dependency and demands on the state (either in theform of state jobs or unemployment payments). Foreigndirect investment in the energy sector compensates fordeficiencies in local capital markets. At the same time it

89


Generalbenefitsof investmentsin energy

Activities underthe UNFCCCcould createadditionalinvestmentopportunities

provides access to advanced technology, know-how andproduction techniques, as well as advanced managementtechniques.

In the United Kingdom, studies of the impact of the oilindustry on employment levels estimate some 28,000employed in the offshore petroleum sector. Ten timesmore work in onshore jobs spread throughout thecountry, involved to varying extents in supporting andservicing the needs of the offshore industry. In a 1993study, Statistics Norway assessed the impact, both directand indirect, of the oil industry on its economy. The oilindustry and its multiplier effect was credited with halvingunemployment from almost 11% to about 6%.The Studyestimated that GNP growth rates between 1972 and1993 which averaged 3% would have been only 1%without energy investment.

In the United States, the development of the Prudhoe Baypetroleum reserves has had a tremendous impact onAlaska, with over 47% of the state economy tied to oilproduction and oil investments accounting for almost40% of total investment. About 30% of all Alaskans areemployed in oil-related activities with 10,200 direct jobscreated for each $1 billion invested and an estimated50,800 total jobs if the multiplier effect is considered.Revenues from the development of energy resources canprovide long term security as well. Since the 1970’s,Alaska has saved a large share of its oil receipts andreinvested them into a diversified portfolio of assetsoutside Alaska. The Fund now totals some $24 billionwith $750 million disbursed in 1997 or $1,300 to everyAlaskan. In 1996 the total income from the Fund equalledtotal oil revenues. Other funds in oil producing countriesand regions have not been as successful, due to lack ofpublic scrutiny and oversight, poor investment choices orthe use of the funds for short-term budget needs.

90

Benefitsin the UK

and Norway


The Alaskanexperience

Conditions for Investmentin the Energy Sector

■ Risk – Distribution and Reduction

Perceived risk affects decisions on whether to invest and,if so, how much.The higher the risk, the higher the returndemanded and, in most cases, the fewer the investorsprepared to participate.

One of the most important considerations for potentialinvestors will always be a country’s level of political andeconomic stability.This is of course an issue which goesfar beyond the energy field.

Private investors are better able than public bodies tojudge and minimise commercial risks such asdisappointing geology, project delays and cost overruns,or a failure of anticipated demand. If governments assumethose risks (and private companies have been known toask them to do so) the purpose of private investment isdefeated. But Governments can act to reduce changes inlegislation and policy which make the investmentenvironment unpredictable and unfair.

A key element in risk reduction is predictability. Giventhe flight of capital from some countries, it is just asimportant to decrease political risk for nationals as forforeign private investors. Foreign investors are at adisadvantage because of remoteness and unfamiliaritywith the local context. They can, however, be givenadditional assurance against political risk by internationalor bilateral treaties. The more unstable a country’sperceived environment, the more benefit it will obtainfrom being party to an international agreement whichenhances investment conditions.

In considering a potential investment, investors willevaluate other financial, regulatory, contractual and

91


Perceivedrisk affectsinvestors’decisions

Commercialrisk should staywith thecompanies

Internationalinvestorscan be givenadditionalassurance

operational risks. Those for which governments areresponsible are access to investment opportunities andoperation once the investment is made.

■ Access to Investment Opportunities

Access to invest in the energy sector is normallyregulated through licences, permits, concessions,contracts, etc.This section concentrates on bureaucraticdifficulties and possible discrimination in obtaining suchpermits. In the energy sector, monopolistic structures arepossibly the largest constraint on private investment.Theexistence and behaviour of monopolies and especiallynatural monopolies are analysed. New investmentopportunities have and will be created throughprivatisation and reductions in monopoly power.

Difficulties experienced by one energy company inmaking an investment in a particular country will affectthe willingness of other private investors to considermaking investments there. In any case, the originalcompany will have had plans to expand on its initialinvestment, either by developing other oil fields or byconstructing petrol stations to sell the output of hisrefinery.Those investments too will be lost.

Bureaucracy/Administration

One of the most pervasive deterrents to privateinvestment is the amount of bureaucracy and elaboratenegotiations required at many different levels ofadministration, with many possible points for reopeningmatters.This is especially daunting to small and mediumsize companies.

Major investments in natural resources almost alwaysrequire negotiations between the owner of thoseresources (often the State) and the investor. Moreover, in

92

Especiallysmall

companieshampered by

excessivebureaucracy


all countries major projects need to obtain a variety ofplanning and other consents from national, regional andlocal authorities. Again, the conditions under whichinvestors may proceed while minimizing environmentaldamage are likely to require detailed negotiationsbetween planning authority and enterprise.

The potential for damage caused by excessive adminis-trative procedures can and should be restricted by:

■ a close review of the requirements for permissions,licenses, etc. to see if all are strictly needed;

■ covering as many of the requirements as possible bygenerally applicable rules that minimize the scope foradministrative discretion and provide for appealsagainst refusals of permissions or unjustified conditions;

■ minimizing the number of stages through which anapplication has to go and setting time limits for eachstage;

■ clear division of responsibility between differentauthorities;

■ ensuring that consent once granted is irrevocableexcept on payment of compensation;

■ training programmes for administrators in transitioneconomies.

Discrimination

Ill-considered administrative requirements deter allprivate investors, both domestic and foreign, but theybear more heavily on the latter because of theirunfamiliarity with local conditions. Some measuresdeliberately discriminate against foreigners wishing tomake investments.

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Potentialdamage causedby excessivebureaucracycan be limited

The subject of investment admission is a relatively newissue in international agreements. Most bilateral treatiesdo not define obligations relating to the admission offoreign investments. The North American Free TradeAgreement (NAFTA) and the Supplementary Treaty tothe ECT, on which general agreement on the text hasbeen reached, do address this issue. In general, theycontain an obligation to refrain from introducing newmeasures which discriminate on grounds of nationality,together with voluntary undertakings to reduce existingdiscriminations.

NAFTA has an annex enumerating all exceptions to non-discrimination. Exceptions in the energy sector have tobe notified under the ECT. During the negotiation of theSupplementary Treaty to the ECT there was an extensivesurvey of exceptions. (These did not of course includeexceptions in OECD-countries not taking part in thenegotiations such as Korea, Mexico, New Zealand Canadaand the United States). The main findings were:

■ of the 50 ECT countries, 12 reported no exceptions.These included, among the G8 countries, Germanyand the United Kingdom;

■ slightly over 100 exceptions existed in matters suchas land ownership, privatization, registration orscreening, and reciprocity.

It was noted that many of these exceptions are notapplied in practice and there is in any case a generalcommitment to remove all such exceptions over time.

It is doubtful whether the exceptions relating toregistration and reciprocity have any substantial effect onadmission to invest in the ECT-countries. Powers toscreen and refuse foreign investments have been usedvery sparingly. Limiting foreign participation in priva-tisation can be very costly to the country concerned but

94

Coverageof investmentadmission in

internationaltreaties


Examinationof existing

discriminatorymeasures

Effect ofdiscriminatory

measures

it is less damaging to foreign investors, since there havebeen no restrictions on subsequent resale of privatizedassets. Discrimination in land purchase, which existedgenerally in the transition economies could have a doubleeffect on foreign investment, since it deprives them of amain source of collateral for loans and may raise sitingproblems. Lack of clear title to land may also affectdomestic investors in transition economies.At the least,those countries which wish to attract foreign investmentshould ensure that there is an alternative to ownership inthe form of secure, very long-term transferable leases.

Market Structure

Private investors will equally examine the structure ofenergy markets in the host country. In general they willdirect investments to markets where there is a highdegree of liberalisation and no unnecessary restrictionson access, competition or trade. Minimisation of direct orindirect government interference is important inensuring that markets operate effectively as is control ofmonopoly behaviour. Economies in transition arecommitted to energy market reform as part of theirtransition away from planned economy systems.

There are a number of possible steps on the way to acompetitive market:

■ contracting some functions out to the private sector;

■ abolishing legal monopolies;

■ encouraging joint ventures between state and privatecompanies;

■ adopting new legal provisions while encouraging theentry of private companies into a monopolycompany’s field of activity;

■ limiting vertical and horizontal integration;

■ privatisation.

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High degree ofliberalisationattractsinvestments

Steps towardsa competitivemarket

Studies covering the 55 OECD and ECT countries showthat the prevalence of energy monopolies varies from nilin some countries to almost 100% sectoral coverage inothers. Monopolies vary significantly between and withincountries in terms of coverage, responsibilities,organisation, independence of government and how theyare regulated.

For oil, only two out of the 55 countries maintain a legallyprotected monopoly on production, and there arevirtually no monopolies downstream. In a handful ofcountries there are de-facto monopolies with only onestate-owned company which has no legal protection ofits monopoly position. Gas has historically had a highdegree of monopoly. While no country has a monopolyon gas production, approximately 20% of them have alegal monopoly for gas transport, and authorisation toexport is often limited. Effective monopsonies for thepurchase of gas production also exist. On the gasdistribution side, the prevalent model is a network ofregional monopolies. More than half the countriesmaintain legal monopolies encompassing the electricitysector (production, transmission and distribution).Reforms in the gas and electricity sectors are, however,going ahead in a number of these countries, reducingmonopoly structures.

In the past two decades, there has been growingattention throughout the world to the behaviour ofmonopolies and state companies, and a general movetowards liberalisation and reduction of governmentintervention. Studies so far support the conclusion thatwhere it is possible to establish competition in theenergy product market, demonopolisation gives clear andmeasurable benefits. When competition is limited orabsent, there is no clear evidence that private firms aremore efficient than publicly owned companies. In the

96

Essentialreformsprior to

privatisation


Legalmonopoliestend to be

sectors withinherent

monopolyfeatures

Wherecompetition

exists there arebenefits fromprivatisation

absence of competition private firms have to beregulated, which can also significantly reduce efficiencygains.

There may be arguments for maintaining a stateenterprise to operate a justifiable monopoly activity. If,however, that enterprise engages in competitive as well asmonopoly activity, the economic distortions resultingfrom cross-subsidies and the deterrent effects on otherpotential investors may be very damaging, and theyshould therefore be strictly controlled. Accordingly,competition policy must give a high priority to separatingjustifiable monopoly activities from those activities wherecompetition can be introduced.

Several approaches have been introduced to minimise thefunctional extent of the monopoly or dominant positionsand to reduce their ill effects.The two main approachesare to separate production or generation from otherfunctions (which may in turn be further separated) or topromote periodic competition for the ownership ofsystems. In Norway, all customers of electricity, includingindividual households, can choose a new supplier for a feeof $30.The local distributor is subject to regulated thirdparty access, while the main transmission lines are ownedby one company providing open access. In England andWales, a similar system exists for gas and electricity in thecommercial and industrial markets, and residentialmarkets are being liberalised.

In some countries state industries have been seen as abetter option than that of maintaining detailed regulationin sectors with strong monopoly characteristics. Statecompanies can also be a means of securing such benefitsas the performance of public service obligations orregional equality of tariffs. The maintenance andestablishment of state industries may, however, tend to

97


Separationof monopolyactivitiesfrom potentialcompetitiveactivities

Competitionhas beentested out ina few countries

The existenceof stateindustries maydiscourageprivateinvestment

discourage private investment, even if they are notaccorded monopoly rights or dominant positions. Theypose two inherent risks:

■ while steps can and should be taken to avoidGovernment interference in day-to-day operations, itis difficult to avoid distortion of commercial objectivesby political considerations. Even in the absence ofgovernment intervention, state enterprises could givepriority to their own political agenda by over-investingin security, expanding their systems beyond the pointof cost effectiveness, taking on new functions orseeking autarchic solutions when normal marketsolutions would be less wasteful;

■ state industries can and should have financialobjectives set for them both in aggregate and forindividual activities. But the state companies are likelyto be involved in the shaping of those objectives andwill be capable of hiding or excusing any failures inachieving them. Financial objectives are no substitutefor the disciplines of the market.

Monopolies may successfully balance supply and demand,particularly if, as in the gas industry, they control bothsides of the equation.They may also, by shadow pricing,achieve a good allocation of resources which maximisesthe sum of consumer and producer surplus. But, whetherin state or private hands, they will lack the dynamicadvantages of private entrepreneurs in competitivemarkets. If they are also state entities, their netinvestment requirements will be borne by the state andmay therefore reduce the scope for other publicexpenditure.

It is of paramount importance that once direct regulationhas been abandoned or a monopoly has been broken up,competition laws (in particular with regard to mergers

98

Companies oftenwant to reduce

competition


and acquisitions) should be put in place and fully applied.A concern in all countries, but particularly in manytransition economies is that there might be no practiceor policy to control mergers. Potentially, some of theadvantageous competitive structures may be lost ifmerger activity is not vigorously controlled. The publicauthorities need adequate powers to monitor marketsand prevent the subversion of competition. The UKpower market is a case in point, where reintegration viaownership links became an issue in 1995 as soon as theinitial restriction on mergers and takeovers was lifted.

International standards do not exclude monopolysituations, but there is an emerging consensus that themove to a market based economy should take place inthe context of respect for basic principles such as non-discrimination.The IEA countries have a long experiencewith strengthening market policies in the energy sector.All the G8 countries together with the other EnergyCharter signatories have taken on a political commitmentto strongly promote access to local and internationalmarkets taking account of the need to facilitate theoperation of market forces and promote competition.

Under certain conditions, privatisation is a valuableoption for liberalising markets. The main objective is toobtain the efficiencies of a competitive market system.The fewer the restrictions on eligibility to buy share-holdings, the more money is likely to be obtained for theprivatised asset and the more efficiently it is likely to berun in the future.

There are particular reforms which are essential or highlydesirable before privatisation:

■ restructuring of the enterprise to be privatised sothat it does not have a monopoly or dominantposition;

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No provisionsagainstmonopoliesor statecompaniesin treaties

The fewerthe restrictions– the largerthe benefits

■ elimination of any remaining problems of non-payment or payment in kind, and introduction ofeffective bankruptcy procedures;

■ introduction of proper company law and rules ofcorporate governance so that minority shareholderscannot be cheated or managers protected fromcommercial disciplines.

There are other problems in achieving competitivemarkets, particularly in the energy sector. The mostdifficult derive from the monopoly characteristics of thefixed transport systems needed to move electricity andgas, and to a lesser extent other fuels, to their consumers.The monopoly character depends on the cost of entryfor a competitor.The cost of having parallel distributionsystems for gas and electricity competing in the samearea is very large.These costs are however changing withtechnological and administrative developments (telecom-munication is a good example).

Access to systems for transporting energy to consumersis vital to the viability of investments in crude oil andnatural gas production, and in electricity generation.Depending on geographical location it may also beimportant for investments in the downstream oil sector.Before committing themselves to a long-term investment,companies will want to be sure that they can move theirproduct to domestic and/or foreign markets oneconomically viable terms.

But the behaviour of monopoly transport networkowners may jeopardise investment decisions. A monopolyor dominant network owner may be motivated to makeexcess profits and/or to create for itself a competitiveadvantage in product markets. The establishment ofregulated, separate network companies will remove thecross-subsidies to other sectors and control profits.

100

Access to gridsimportant

for investors


Governments will need to clear the way for new privateinvestments in energy production and generation byproviding a legal framework ensuring access to energytransportation systems. The extent and manner ofsafeguarding access, including tariffs and other conditions,depends on particular circumstances. Strong competitionrules may be sufficient in some cases to prompt asatisfactory deal between the network owner andproducer or customer. Regulation is not always easy; ifprivate risk investment is to be attracted totransportation systems as well as to production, then abalance has to be found between producers, transportersand consumers; and among the original users of thesystem, who will have borne the main risks, andnewcomers.

Different approaches will apply in dealing with themonopoly characteristics of electricity and gas industriesdepending on whether the industries are in the public orprivate sectors. In recent years, there has been a cleartrend away from strong direct influence by governmenton state-owned companies to a more arms lengthrelationship and creating greater commercial orientationin state company management. Increasingly electricity andgas industries are subject to control by regulators whoare independent of both government and the regulatedsector.

Independent regulation of energy industries is establishedpractice in the United Kingdom, United States andCanada. For countries with economies in transition, forexample, in Russia, the establishment of the FederalEnergy Commission with responsibilities in the area ofaccess to the oil export system, and oil and gas pipelineand electricity tariffs, is a valuable step in this direction.Its independent status will be vital to its ability to achieveits goals.

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Independentregulationof integratedtransportationsystems

Increasingly,directgovernmentinfluenceis transferredto independentregulators

Particular problems may arise in relation to integratednetwork systems connecting a number of points of originand points of destination in more than one country.Themost beneficial arrangement overall may not be theoptimum for each of the individual countries, andarrangements for ensuring that benefits are fairly sharedwill not be easy to establish.The multinational oil productsystem of the Rhine appears to have worked efficientlyon the basis of a treaty. But some of the logistical systemsfor oil, gas and electricity in and between the NewlyIndependent States have broken down or are in danger.Formerly those systems were national and have becomeinternational through the breakup of the Soviet Union.The Newly Independent States may be tempted to createtheir own self-contained systems. This would result inallocation of more investment in infrastructure than a co-ordinated approach.

The Energy Charter Treaty establishes rights andobligations for importers and exporters wishing totransit another ECT country. It is the only multilateralagreement on grid-bound transit. It does not, however,guarantee mandatory third party access, interfere withpurely commercial transactions or define appropriatetariffs.Transit is discussed in detail in a separate paper.

High cost energy resources have been and are developedworld wide,while cheaper resources are left in the ground.This is an unfortunate consequence of the geographicalconcentration of resources and monopolistic behaviourcoupled with large political uncertainties. This waste ofresources can be reduced through closer economic andpolitical co-operation, underpinned by international treaties.

102

Co-ordinatedapproach

reducesinvestment

needs


■ Operation Once the Investment is Made

Once investments are made, companies will need to havethe right to enjoy their investments without unreasonableinterventions from governments or regulators, ordiscrimination in favour of their competitors. It will beessential for potential investors to know that theiractivities can be conducted under a coherent frameworkof law guaranteeing their rights and ensuring performanceof contracts and other agreements. The rate andcertainty of return from any given energy investment willdepend crucially on the relevant tax system. Otherimportant financial considerations will include access toinvestment capital and freedom from restrictions oninternational transfers. Access to markets and internaltransport systems will be essential. Nor shouldcompanies suffer from restrictions on international tradein energy products, equipment or services.

Legal environment

Legislation governing energy investment needs to betransparent, stable, predictable and co-ordinated withother laws to make clear the overall legal regime.Otherwise it will leave scope for arbitrary decisions andbe a serious disincentive to investors. If regulatory andfiscal power is shared between different levels ofgovernment, the demarcation of responsibility betweenthese authorities should be clearly defined. This is aproblem in many federal systems with large energysectors, as each level of government tends to see theenergy sector as a lucrative source of tax revenue foritself. In OECD countries, the various levels ofgovernments have sought ways to co-operate in order toavoid deterring investors by excessive levels of combinedtaxation and overlapping or conflicting regulations.

103


Legislationgoverning energyinvestmentneeds to betransparent,stable,predictable andco-ordinatedwith other laws

One of the worst fears for investors is the possibility offundamental changes to the legal regime governing aninvestment which would undermine the fiscal orcontractual undertakings that formed the basis of originalinvestment decision. Delay in developing an adequatelegal regime or reliance on piece-meal regulation alsoheighten investor uncertainty.This is a significant issue fortransition economies These economies need to movemore quickly to put in place comprehensive systems oflegal regulation which will provide strong assurances toinvestors making large-scale long-term energy investments.

There is consensus in the investment community aboutthe level of guarantees necessary to offset political risk.Investors will base their investment decisions on anassessment of the soundness of the local legal regime inthat respect. In OECD countries, it has taken decades todevelop effective legal and tax regimes which balancepublic and private needs. Governments which cannot relyon an historical pattern of relative stability or longexperience in a market economy must take positiveactions to engender investment confidence and establishstability through strong legal guarantees. Participation ininvestment treaties, such as bilateral investment agree-ments and the Energy Charter Treaty, will do much toprovide investors with the degree of assurance they need.

Most bilateral investment protection treaties andmultilateral treaties such as NAFTA, and specifically forenergy, the Energy Charter Treaty (ECT) lay down certainabsolute legal requirements. There are differences ofdetail but the more advanced provisions include:

■ requiring a Contracting Party to fulfil obligationswhich it has entered into with an investor of anotherContracting Party so that a breach of an investor’sagreement with a host country will become a treatyviolation;

104

Pattern ofstabilityneeded

through stronglegal

guarantees


Concernsabout

possibility offundamental

changes to thelegal regime

governingan investment

Certain absolutelegal requirements

in bilateral andmultilateral

treaties

■ permitting investors to employ key personnel of theirchoice, regardless of nationality, so long as suchpersonnel have work and residence permits;

■ allowing a foreign investor freely to transfer out of thecountry, in fully convertible currency, the capital it hasinvested and any associated earnings;

■ compensating foreign investors for losses resultingfrom civil emergency at least to the degree to whichnational investors are compensated and providing forfull, adequate and prompt compensation if the lossresults unnecessarily from the country’s own actions;

■ submitting expropriation to the tests of due processof law and national interest and providing for full,adequate and prompt compensation for assetsexpropriated;

■ giving the investor a right to pursue bindinginternational arbitration under the treaties’ disputeresolution provisions.

Many actions by governments, e.g. to control the macro-economy or introduce environmental and safetylegislation, can affect investment earnings. The bestassurance here for the foreign investor is a guaranteethat it will receive the same treatment as the domesticinvestor. International investment treaties provide for thisguarantee.

Besides generally accepted standards for investment,investors and major lending and financing institutionshave a need for a national legal regime that meets basiccriteria for reduced political risk. In this context theyhave raised questions as to whether legislation in thetransition economies does in fact provide appropriateassurances. In the case of Russia, major studies havenoted that the existing Joint Venture licensingarrangements are based on an administrative system that

105


Same treatmentas nationalinvestor providesa generalguarantee

views the Subsoil License as the supreme document,while the agreement among parties to the Joint Ventureis only secondary. This exposes the investor to severalsignificant risks. The terms of the license to use thesubsoil are subject to unilateral change by new legislationand are terminable by the government on variousgrounds. It is subject to all applicable taxes at all levels ofgovernment, and no protection is provided againstadverse changes in tax laws or other laws. There is noclear right to export, and disputes are not subject toimpartial adjudication because there is no contractualrelationship between the Joint Venture partners and thegovernment.

Experience in many countries has shown that investorsregard Production Sharing Agreements (PSAs) as analternative mechanism on which to base majorinvestments especially while an overall tax regime is beingdrafted and put into place. The recent boom ininvestment in Azerbaijan shows how legal and fiscalarrangement for PSAs can attract investment, especiallywhen it is underpinned by strong treaty obligations.Azerbaijan was among the first countries to ratify theECT. It has signed PSAs involving total investment of over$30 billion since September 1994. In Russia, the Sakhalin Iand Sakhalin II PSA projects are already underway. Theyare expected to bring the Sakhalin region more than$40 billion in investments over the next 10 to 15 years.

There are immediate and relatively low-cost measuresthat governments can take to promote investorconfidence, such as becoming party to internationaltreaties, bilateral and multilateral, which provide for basicguarantees for investors, including access to internationalarbitration. The Washington Convention on theSettlement of Investment Disputes and the EnergyCharter Treaty are obvious examples.

106

Experiencewith PSAs


There areimmediate and

relativelylow-cost measures

to promoteinvestor

confidence

Crime and corruption form a particular risk in theenergy sector because of the large sums involved in anyinvestment. Inadequate and vague laws, which providescope for arbitrary decisions, wide discretion in theirapplication or differential price controls provideopportunities for corruption and crime. Governmentsmust balance the need to minimise the risk that mistakesmay be made or delegated authorities may be abused inconcluding agreements against the need to encourageprivate investment. If the approval requirements becometoo onerous or restrictive or the process too complexand lengthy, investors are likely to be deterred especiallyif there are other less risky opportunities to investelsewhere.

Financial environment

The principles which form the basis of effective fiscalregimes have not fundamentally changed over thecenturies. Adam Smith, in his “Wealth of Nations”published in 1776, described these principles as: Equalityof treatment of taxpayers, Certainty for taxpayers as tothe impact of the tax, Convenience of payment fortaxpayers and Cost effective collection for thegovernment.Today a multiplicity of approaches, levels oftaxation and royalty regimes and differing levels of risk orattractiveness as perceived by the investor need to betaken into account. In a competitive world, governmentshave to match the need for revenue with the investor’sperception of the opportunity cost of investingelsewhere.

Risk of fiscal change is a major concern to investorsmaking large upfront investments, especially in regionswith little or no history of fiscal stability. Frequent taxchanges are due in part to the nature of gross-revenuebased regimes where governments need to make

107


If approvalrequirementsbecometoo complexand onerous,investorsare likely tobe deterred

Governmentsmust matchneedsfor revenuewith investorperceptionof country andproject risk

Risk of fiscalchange isa major concernto investors

adjustments to benefit from changes in prices or costs.Profit-based systems are more self-adjusting and give abetter basis for investors to assess the fiscal impact overthe life of their investment project. Such systems do notimpose a heavy tax burden in the early years ofproduction which would negatively affect projected rateof return. This can be seen in the chart below, whichcompares the impact on project rate of return and thetax revenues over the life of the same oil project underthe Canadian tax system (a representative of profit-sensitive tax regimes) and under the current Russian taxsystem, which is essentially based on gross revenues.Taxation which aims to maximise short-term governmentrevenue may jeopardise the long-term economic goals ofattracting investments, providing long-term employment,income and a widening of the tax base. Finding the righttax structure is of particular importance to Russia wherethe oil & gas industry accounted for over 50% of federalgovernment revenues in 1997.

108

Taxation thataims to maximise

short-termgovernment

revenue mayjeopardiselong-term

economic goals


Comparison of Government Take andImpact of Fiscal Systems on Project Rate of Return

Gov

ernm

ent T

ake

($ m

illion

)

0

20

40

60

80

100

120Resulting rate of return in Canada 10% Resulting rate of return in Russia 0%

Russian Gov't Take

Canadian Gov't Take

Years

Gov

ernm

ent T

ake

($ m

illion

)

0

20

40

60

80

100

120Resulting rate of return in Canada 15% Resulting rate of return in Russia 7%

Russian Gov't Take

Canadian Gov't Take

Years

Low Oil Price Case($102/Tonne)

Average Oil Price($131/Tonne)

Conformity with OECD countries in the area of taxationwill need to be combined with a sound and professionallyrun public and private audit system. That system shouldbe based on generally accepted accounting principles, forpurposes of checking and monitoring tax complianceunder a much more complex tax system.This should inturn reduce the perceived need to set norms to controlmaximum allowable business costs, thereby reducing stillfurther the differences between countries formerly rununder central planning and OECD systems of taxation.This could lessen or remove altogether investorconcerns about double taxation or problems with taxcredit in home countries. Implementation of an effectiveTax Code will be a key component to build andstrengthen the ongoing process of reform to a marketeconomy.

There should be no restrictions on international monetarytransfers at the investment or operational stages, asinvestors will need access to capital from national orinternational lending institutions, consistent with normalcommercial criteria.

Market operation

For most goods free markets have proved historically tobe the most efficient means of matching bids and offersand reducing costs. Lack of correct feedback from themarket can lead to serious distortions. Historically in theenergy industry lack of proper market signals has moreoften led to too much investment and misplacedinvestment, rather than too little investment. But in somecountries and some energy sub-sectors, the combinationof a lack of market reform and inability to raise revenuefor public sector investment threatens to result in toolittle investment, failures in supply and lost opportunitiesfor export earnings.

109


A profit basedtax systemshould becombined withan auditsystem basedon acceptedaccountingprinciples

Free marketsreduce costs

Markets do not eliminate risk. Expected demand may notemerge, competitors may obtain access to cheaper rawmaterials, new technologies may make a process orproduct obsolete, transport to customers may not beavailable on terms which allow profit, or may beinterrupted. But, to the extent that risk can be reduced,investment becomes more attractive. Private investorsmay seek to transfer some of these risks to the publicsector, particularly where an investment depends onnegotiation. But Governments and other public sectororganisations are less adapted to adjusting to risks andtend to fail on a grander scale when the risk has beenmiscalculated.

In transition economies the issue of non-payments is amajor problem in making markets work, especially in theenergy sector. Non-payment for energy and other goodscontinues to be a vicious circle. Large state-ownedindustrial and commercial companies are major “non-payers” both for services received and in wages. InRussia, inter-company non-payment is estimated at over$85 billion; non-payment to the United Energy Systems isestimated at over $16 billion and UES in turn owes hugeamounts to Gazprom and other suppliers. This massivegridlock of debt makes investment difficult or impossibleand paralyses much of the industrial sector.A number oftransition economies have passed laws enabling utilitiesto cut off non-paying customers, but most such laws havebeen watered down by exceptions and are difficult toimplement in practice. International non-payment amongtransition economies is also a major problem (especiallyfor gas). Russia has concluded debt-for-equity swaps witha number of countries; problems remain, however, withsome of them.

110

Risks are noteliminatedin markets


Non-paymentsseriouslyhampers

the effectiveworkings ofthe market

Government interventions in market mechanisms may bedesigned to attract private investment (e.g. protectivetariffs, subsidies) or undertaken for political reasons.Thebeneficial effects of interventions to attract privateinvestment are likely to be of limited long-term valuebecause investors have no assurance that whatGovernments did, they will not undo. Examples in theenergy sector of such interventions are:

■ price controls in the absence of a monopoly situation;

■ subsidies;

■ tariff structures distorted by regulation;

■ local purchasing requirements;

■ import tariffs;

■ export tariffs and quotas;

■ requirements to supply equipment from the homemarket;

■ pressures to construct or use domestic refineries.

The World Trade Organization has rules that ban orcontrol many such measures.The Energy Charter Treatyapplies most of those rules in the energy sector to thenon-World Trade Organization parties (with theexception of tariffs for which there is a separate regime).

Other Government interventions may be made for non-economic reasons, to protect the environment, enhancesafety and health, protect poor consumers etc.These mayin fact have the incidental effect of increasing investment.

Recommendations to Governmentson Energy Investment

Governments should address the need for attractinghigher levels of private sector investment by liberalisingenergy markets and ensuring fair competition, includingcontrol of monopoly behaviour.

111


Doubtfulbenefits ofinterventionsin marketmechanisms

Procedures for granting investment rights should bereasonable, practical, transparent and based on publishedcriteria.

Where investment opportunities are generally available,the scope for private sector investment should bemaximised by giving companies equal access to thoseopportunities without discrimination by nationality or onother subjective grounds.The national economic benefitsarising from a particular investment will not bedetermined by the nationality of the investing company.

Privatisation opportunities should, except in very limitedcases of clearly defined national interest, be open tocompanies without discrimination on grounds ofnationality.There should be no constraints on subsequentresale and purchase of shareholdings or other assetsafter privatisation.

Investment prospects should be enhanced by a stable andcomprehensive framework of national law, properlyimplemented at all levels of administration, includingenforceability of contracts, debt recovery mechanismsand recourse to effective national and internationaldispute settlement procedures. The respectiveresponsibilities of national, regional and local authoritiesshould be clearly defined. Investors should receiveeffective protection from crime and corruption.

In countries where the legal framework for upstream oiland gas investments and the relevant taxation rules donot yet provide sufficient confidence to investors,Governments should include effective alternative optionssuch as Production Sharing Agreements into theirpolicies.

Taxation systems should be clear, stable, non-discrimi-natory and based mainly on profits rather than on grossrevenues or production.

112


No constraints should be placed on internationalfinancial transfers relating to energy activities, or onaccess to capital funding.

To enable resources to be allocated efficiently, Govern-ments should allow energy prices to reflect marketconditions.

In accordance with international standards, there shouldbe no discrimination in the operation of national energymarkets.

Governments should have legal regimes ensuring accessto energy transport systems on fair terms, under rulesapplied by operationally independent regulatoryauthorities.

Companies should be free to sell their production inforeign markets through the full application by govern-ments of World Trade Organization Rules. Consistentwith World Trade Organization Rules, there should be nobarriers to purchases of energy equipment, services ortechnology from the most economic source, whetherthat source is within the country concerned or abroad.Government policies in this area should acknowledge thebenefits of transfers of modern technologies.

As well as energy supply projects, investments in energyefficiency and environmental quality should be given highattention in energy investment policies.

The governments concerned should continue to pursue,as a matter of priority, ratification of the 1994 EnergyCharter Treaty.The Treaty remains open for accession byother countries.

113


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ARMSTRONG, Mark, COWAN, Simon, and VICKERS,John, 1994. Regulatory Reform - Economic Analysis and BritishExperience. MIT Press: London, UK.

BONBRIGHT, James C., DANIELSEN, Albert L., andKAMERSCHEN, David R, 1988. Principles of Public UtilityRates.Arlington.

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