Competitive Electricity Markets and SustainabilityAmerican and European Union Competition Law,...

Competitive Electricity Markets

and Sustainability

Edited by

François LévêqueProfessor of Economics, Ecole des mines de Paris, Cerna

iii

Contents

1. Investments in competitive electricity markets: an overview 17

François Lévêque

2. Investment and generation capacity 42

Richard Green

3. Generation technology mix in competitive electricity markets 81

Jean-Michel Glachant

4. Problems of transmission investment in a deregulated power 111

Steven Stoft

5. Patterns of transmission investments 169

Paul Joskow

6. Long term locational prices and investment incentives in the

transmission of electricity 239

Yves Smeers

7. Compatibility of investment signals in distribution, transmission and

generation 293

Ignacio Pérez-Arriaga and Luis Olmos

Index 369

iv Competitive Electricity Markets and Sustainability

iv

List of figures

Figure 2.1 The determination of electricityFigure 2.2 How the capacity mix affects pricesFigure 2.3 Investment in England and WalesFigure 2.4 Investment in FinlandFigure 2.5 Investment in NorwayFigure 2.6 Investment in SwedenFigure 2.7 Investment in the United StatesFigure 2.8 The determination of electricityFigure 3.1 Present-Day Cost of Generating Electricity in UK (Year

2003/04)Figure 3.2 CCGT Cost of entry by country in Europe in 2005Figure 3.3 Spark Spread in Texas 1999-2002Figure 3.4 Finnish comparison of generation costsFigure 4.1 Defining congestion rent and congestion costFigure 4.2 Cost to consumers compared with congestion cost and rentFigure 4.3 Relationship of congestion to a transmission-cause reliability

problemFigure 4.4 A positive present value is not sufficientFigure 4.5 Lumpy technology may not exhibit returns to scale in the

long runFigure 4.6 Option rights reduce the feasible set of rightsFigure 4.7 Optimal investment in lumpy technology may be profitableFigure 4.8 Optimal Investment eliminates congestionFigure 4.9 Investors should not capture full social benefitFigure 7.1 Process of computation of locational signalsFigure 7.2 Average L and G tariffs in EuropeFigure 7.3 L nodal tariffs in EuropeFigure 7.4 G nodal tariffs in EuropeFigure 7.5 Original and new L tariffs within Spain for the IEM-13

systemFigure 7.6 Original and new G tariffs within Spain for the IEM-13

systemFigure 7.7 Comparison between the transmission tariff and the net inter-

TSO payment for 17 European countries.Figure 7.8 Evolution of the energy price of several Power Exchanges

belonging to Europex from January 2000 to November 2004Figure 7.9 Proportionality principle in average participations

v

List of tables

Table 3.1 Nuclear generation costs in the early XXIst Century (byMWh)

Table 3.2 Nuclear generation costs in the 2003 MIT StudyTable 3.3 Nuclear versus Gas CCGT cost of capital analysisTable 4.1 Three views of congestionTable 5.1 Reliability upgrade projects New England regional expansion

plan 2004 ($ millions)Table 5.2 Schedule of transmission network use of system generation

charges (£/kW) in 2004/2005Table 5.3 Schedule of transmission network use of system generation

charges (£/kW) and energy consumption charges (p/kWh) for2004/2005

Table 5.4 England and Wales system operator incentive mechanismunder NETA

Table 5.5 PJM inter-connection charges proposed ERIE-West HVDCTable 5.6 Market window ‘Economic’ transmission projects in PJM as

of November 2004Table 5.7 Examples of transmission congestion mitigated by reliability

investments in PJMTable 7.1 Impact of different factors on the total generation capacity

needed to supply a 384 MW load, located close to a mainconsumption centre, from two different locations, one closeto the load centre and the other one close to an entry point forLNG

Table 7.2 Comparison of the cost savings involved in supplying a 384MW load located close to a main load centre

vi Competitive Electricity Markets and Sustainability

vi

Contributors

Richard Green

Richard Green is professor of economics at the University of

Birmingham and Director of the Institute for Energy Research and Policy.

He has been studying the economics and regulation of the electricity

industry since 1989, just before the industry in England and Wales was

privatised. With David Newbery, he was responsible for the most influential

study of competition in the British electricity spot market. He has written

two books, and more than 40 articles and book chapters, mostly on the

electricity industry and its regulation. He is an associate editor of the Journal

of Industrial Economics, and on the Editorial Board of the Journal of

Regulatory Economics. He has spent a year on secondment to the Office of

Electricity Regulation, and has been a visiting Fellow at the World Bank

Institute, the University of California Energy Institute and the

Massachusetts Institute of Technology. He has been a specialist advisor to

the House of Commons Trade and Industry Committee, and is on the

academic advisory panel to the staff of the UK’s Competition Commission.

Jean-Michel Glachant

Jean-Michel Glachant is tenured professor and Head of the Department

of Economics at the University of Paris Sud (France) where he created the

Network Industry Research Group (GRJM). Prior to joining University

Paris Sud in 2000, he has been all along the 90’s deputy director or director

of the leading French institutional economics research center (ATOM) at La

Sorbonne University. His work focuses on the institutional economics of

competitive reforms in the European network industry. His current work

focuses on the creation of a single energy market in the European Union

extended to 25 Member States. He has advised the European Commission

vii

(DG Energy and DG Competition) on electricity reforms. He has been

member of the Economic Advisory Committee at the French Energy

Regulatory Commission. He is member of the Board of the International

Society for New Institutional Economics (ISNIE), of the Faculty of the

European School for Institutional Economics (ESNIE); partner of the

“Electricity Policy Research Group” at the University of Cambridge, and of

the European Energy Institute (EEI). He received his Ph.D. in Economics

from La Sorbonne University.

Paul L. Joskow

Paul L. Joskow is Elizabeth and James Killian Professor of Economics

and Management at MIT and Director of the MIT Center for Energy and

Environmental Policy Research. He received a BA from Cornell University

in 1968 and a PhD in Economics from Yale University in 1972. Professor

Joskow has been on the MIT faculty since 1972 and served as Head of the

MIT Department of Economics from 1994 to 1998. __At MIT he is engaged

in teaching and research in the areas of industrial organization, energy and

environmental economics, competition policy, and government regulation of

industry. Professor Joskow has published six books and over 120 articles

and papers in these areas. His papers have appeared in the American

Economic Review, Bell Journal of Economics, Rand Journal of Economics,

Journal of Political Economy, Journal of Law and Economics, Journal of

Law, Economics and Organization, International Economic Review, Review

of Economics and Statistics, Journal of Econometrics, Journal of Applied

Econometrics, Yale Law Journal, New England Journal of Medicine,

Foreign Affairs, Energy Journal, Electricity Journal, Oxford Review of

Economic Policy and other journals and books. __Professor Joskow is a

Director of National Grid Transco (formerly the National Grid Group), a

Director of TransCanada Corporation, and a Trustee of the Putnam Mutual

Funds. He previously served as a Director of New England Electric System.

viii Competitive Electricity Markets and Sustainability

viii

Professor Joskow has served on the U.S. EPA's Acid Rain Advisory

Committee and on the Environmental Economics Committee of the EPA's

Science Advisory Board. He is a member of the Scientific Advisory Board

of the Institut d'Economie Industrielle (Toulouse, France) and the Scientific

Advisory Board of the Conservation Law Foundation. Professor Joskow is a

part-President of the International Society for New Institutional Economics

and a Fellow of the Econometric Society and the American Academy of

Arts and Sciences. _

François Lévêque

François Lévêque is professor of economics at Ecole des mines de Paris

and visiting professor at University of California at Berkeley. He is Director

at Cerna, the research centre of the Ecole des mines in industrial economics.

François Lévêque has published several books in antitrust economics

(Antitrust, Patents and Copyright, Edward Elgar, 2005; Merger Remedies in

American and European Union Competition Law, Edward Elgar, 2003), in

economics of regulation (Economie de la réglementation, Editions La

Découverte, 1999 et 2005; Transport Pricing of Electricity Networks,

Kluwer Academic Publishers, 2003) and in economics of intellectual

property rights (Economics of Patents and Copyright, Berkeley Electronic

Press, 2004). In is the author of 50 articles in the same areas. He has

coordinated several large European research programmes on Electricity

Reforms and Energy Policy. He wrote with Jean-Michel Glachant a well-

known policy report “Electricity internal market in the European Union –

What to do next?”

François Lévêque taught economics of natural resources at the Ecole des

mines de Paris (1984-1990), environmental economics at EHESS (1997-

2001) and at Pavia University (1999-2002). He created in 1999 a new major

in law and economics at the Ecole des mines. He has taught industrial

economics at the Ecole des mines since 1996 and Energy economics since

ix

2004. He has also taught EU Competition Law at the Boalt School of Law,

University of California at Berkeley, since 2002.

He has been regularly commissioned by the French government, OECD

and the European Commission to undertake consultancy and participate to

advisory committees. François Lévêque has founded Microeconomix, a

Paris-based boutique specialised in economic analysis of legal

disputes. François Lévêque is member of the French Environment

Accounting Commission and of the Council on Intellectual Property.

Ignacio J. Pérez-Arriaga

Ignacio J. Pérez-Arriaga was born in Madrid in 1948. He received the

Electrical Engineer degree from Comillas University, Madrid, Spain, and

the M.S. and Ph.D. degrees in electrical engineering from the Massachusetts

Institute of Technology (MIT), Cambridge, USA.

He is Director of the BP Chair on Sustainable Development and Full

Professor of electrical engineering at Comillas University, where he was

Founder and Director of the Instituto de Investigación Tecnológica (IIT) for

11 years, and has been Vice-Rector for Research. For five years he served as

Commissioner at the Spanish Electricity Regulatory Commission. He is life

member of the Spanish Royal Academy of Engineering and Fellow of the

Institute of Electrical and Electronic Engineers (IEEE). He is Director of the

annual Training Course of European Energy Regulators at the Florence

School of Regulation within the European University in Florence. He was

the author of the White Paper on the Spanish electricity sector

commissioned by the Government in 2005. He has been principal researcher

in more than 40 projects and he has published more than 100 papers in

national and international journals and conference proceedings. He has

worked and lectured extensively on power system dynamic analysis,

monitoring and diagnosis of power system devices and systems, intelligent

computer design of industrial systems, planning and operation of electric

x Competitive Electricity Markets and Sustainability

x

generation and networks, and regulation of the electric power sector. In this

latter topic he has been a consultant for governments, international

institutions, industrial associations, and utilities in more than 30 countries.

His current research interests are centred on regulation of the electric power

industry, the design of regional electricity markets and energy sustainability.

Yves Smeers

Yves Smeers is the Tractebel Professor of Energy Economics at the

Université catholique de Louvain in Belgium where he is affiliated with the

Department of Mathematical Engineering and the Center for Operations

Research and Econometrics. He received an Engineering degree from the

Université de Liège in 1967, and a degree in Economics from the Université

catholique de Louvain in 1969. He also obtained a MS degree in Industrial

Administration and a PhD in Operations Research from Carnegie Mellon

University respectively in 1971 and 1972. His current research interests

concentrate on the Computational Equilibrium Models and Risk

Management in restructured electricity systems. .His experience in the area

extends from operational to strategic market simulation models. He has

extensively published in the area and acted as project leader on many projects for

the European Commission, the World Bank, OECD and the Belgian government.

He also conducted various assignments for major European gas and electricity

companies, as well as for Regulators. He is currently scientific adviser at the

Department of Strategy of Electrabel/Suez where he works on market simulation

models and risk management. He has recently published several articles in

Operations Research, Journal of Network Industries, Networks and Spatial

Economics and Utilities Policy.

Steven Stoft

Steven Stoft is an economist and independent consultant with twelve

years experience in power market analysis and design. He is the author of

/Power System Economics, Designing Markets for Electricity/ (IEEE, 2002)

xi

and also of many published article on electricity market design. He has

advised PJM’s Market Monitoring Unit since 1999, was an expert witness

for California’s Public Utility Commission and Electricity Oversight Board

(EOB) in their litigation over long-term contracts before the Federal Energy

Regulatory Commission (FERC). Beginning in 2004, he has worked with

the ISO New England in designing their ICAP market and was their expert

economic witness before FERC. He is also working with the EOB on

installed capacity markets for California. Previously he was a Senior

Research Fellow at the University of California Energy Institute, worked on

regulatory and restructuring issues at the Lawrence Berkeley National

Laboratory and spent a year in the Office of Economic Policy at FERC. He

received his B.S. in Engineering Math and his Ph.D. in Economics from the

University of California at Berkeley.

17

1. Investments in competitive electricity markets: an

overview

François Lévêque

1. Introduction

Over the course of the past 20 years, most of the countries in the OECD

have engaged in a competitive opening of their electricity markets. The

incumbents were stripped of their legal monopolies, wholesale markets were

formed, and dedicated organisations assumed management of the

transmission grid. Large consumers acquired the ability to choose their

electricity supplier. This opening to competition brought on a profound

change in the terms of investment in both generation and transmission.

Decisions concerning the construction of new power plants, in particular the

timing and the technology mix (i.e. the proportion of hydro electricity,

nuclear, thermal, etc.) now depend on decentralised initiatives of investors,

and not on public authorities. As to transmission, which remained a

monopoly, the reinforcement and expansion of high-tension power lines are

no longer directly controlled by the generators. System operators have

greater leeway for initiative. Depending on the specific case, they can sell

financial transmission rights, submit investment programs to the regulatory

authority, or invest as they see fit.

In a word, investments in an electricity system that is open to competition

will no longer be coordinated by the same mechanisms as in the past. The

planning that enabled a monopolistic and vertically integrated producer to

adjust base and peak load capacities, as well as generation and transmission

capacities, has been replaced by a series of decentralised decisions partly

based on prices. This new decision set - which involves many agents and

combines market signals with regulation - must be understood in detail. A

18 Competitive Electricity Markets and Sustainability

thorough comprehension is necessary to reveal to what extent, and under

what conditions, competitive opening will result in an investment level that

is consistent with the public interest. Only this will allow identification and

evaluation of solutions to situations of investment shortfall or oversupply

such as those we have seen arise on several occasions (e.g. under-

investment in interconnection capacity in California, and over-investment in

independent gas-powered plants in the United States during the 90s.) This is

the spirit in which this book was prepared.

This first chapter contains five sections. The first section reviews the new

terms of investment in generation and transmission. The second and third

address investment in generation and in transmission, respectively. The

fourth section resumes the discussion of the interface between investments

in generation and transmission that we briefly began in the first section.

Finally, the fifth section provides a preview of some essential points that the

co-authors of this book raise in subsequent chapters, and that were not

mentioned in the preceding sections.

2. The issue

Ideally, an optimal level of investment in the electricity system would

involve joint optimisation of investments in generation and transmission. In

fact, the goal is to minimise the cost of electricity to consumers. From an

economic perspective, generation and transmission are complementary

goods; if the price of one decreases, the quantity sold of the other increases.

The mechanism underlying this phenomenon is simple: Consumers are only

sensitive to the total price of electricity since they do not consume the

generated electricity and the transmission service separately. Consequently,

if the price of a KWh falls, ceteris paribus, they will consumer more

electricity and demand a greater quantity of the transmission service.

Consequently, investments in generation and transmission complement each

Investments in competitive electricity markets: an overview 19

other.

Sometimes, however, investments in generation and transmission are

substitutable. For example, in an isolated region with limited

interconnection with the grid, a rise in local demand can be satisfied by

either reinforcing the line or building a new power plant within the zone. If

both investments occur simultaneously, then neither will be profitable.

When both activities are combined within a single firm, joint optimisation

of investments is deemed self-evident, since the stockholder or manager

maximises overall profits. In an electricity system that is open to

competition, the visible hand of the manager fails to ensure coordination

between generation and transmission. Transmission is separated from

generation in one way or another (i.e. accounting, managerial, or legal

unbundling) in order to ensure that rival generators have equitable terms of

access to the grids.

According to S. Stoft, this new situation opens the door to strategic

behaviour on all sides. In order to provide for future investments in

transmission, the transmission system operator (hereafter, TSO) must be

informed of future investments in generation. Conversely, to plan these

investments in generation, producers require forecasts of the TSO’s future

investments in the grid. To escape from this deadlock, one of these

stakeholders must ‘draw first’ by revealing its intentions and proceeding

with the investment. However, the first to invest becomes hostage to the

other, since it is impossible to move a power plant, or pylons, without

forfeiting the bulk of their value. This is the classical economic problem of

the hold-up occasioned by stranded costs. The upshot is generalised under-

investment: Each party, knowing that it may be taken hostage ex post,

reduces investments ex ante. Thus, we cannot apply the idealised rule for

investment in transmission, which would have the system operator plan

investment by optimising transmission and generation as a function of

future demand and then lay the power lines in the hope that the market will


induce generators to invest according to plan.1

Nonetheless, it is necessary to avert a profusion of waste by finding some

way to coordinate investments in generation and transmission. Various

instruments, such as financial transmission rights and a zone-based rate

structure for the grid, have been proposed in the recent economic literature.

These are described and discussed in the chapters by S. Stoft, Y. Smeers,

and I. Pérez Arriaga and L. Olmos. Before examining them more closely, it

will be useful to separately examine the optimisation of transmission and

generation. Though this simplifies greatly, these two issues taken

individually are far from trivial. Let us examine how to optimise the

utilisation and size of the grid when generating capacity is optimal, and how

to optimise the utilisation and volume of generating capacity when the grid

is optimal.

3. Investment in generation

Aside from grid constraints, what obstacles must the market mechanism

contend with to yield a socially efficient level of investment in generation,

i.e. a level that satisfies the users’ needs at the lowest cost?

The optimal investment in electricity generation is precisely determined

by the theory, which addresses both total capacity and its distribution

amongst power plant types. These latter, in fact, differ both in terms of

variable costs, which are usually linked to the price of fuel, and fixed costs,

which essentially reflect expenditures on construction. For a nuclear power

plant, the former are low and the latter very high; for a gas turbine this is

inverted. Consequently, nuclear plants should be used throughout the year to

meet base-load requirements, while gas turbines should only be called on to

meet peak-load demand at times of the year when there are spikes in

demand.

In his chapter, R. Green presents a simple model of optimal levels of


generating capacity comprising only these two types of plants. Emphasising

a graphical approach, he demonstrates how to identify the load-duration

curve for the 8760 hours in a year and how to translate it into an hourly

price curve. Naturally, the highest price is found when demand is greatest.

As this demand exceeds available capacity, the equilibrium price is not set

at the marginal cost of the last unit generated, but rather at a higher level

equal to the marginal opportunity cost of consumption (i.e. above which the

last consumer prefers to forgo rather than consume). The gap between these

two marginal costs thus allows the peak-load plant that operates for the

shortest period during the year to cover its costs. Notice that this result

contradicts the conventional wisdom that the electricity market is incapable

of ensuring that plants’ fixed costs are covered. This confusion arises from

an overly hasty equating of the equilibrium price with the marginal cost of

generation. In the presence of congestion, as during extreme peaks in this

case, the shortage must be managed and resources allocated to those

economic agents on whom the lack of access imposes the greatest cost.

Furthermore, as R. Green reminds us, economic theory demonstrates

that if the peaking plant that is used least covers its total costs, and if the

allocation among the various means of generation is efficient, then all other

plants can cover their total costs with market prices that are based on

marginal costs.

We note that investors clearly had no doubts regarding the ability of

electricity markets to render new investments in generation profitable. In the

United States, as in England, there was even talk of a boom in the

construction of new power plants, in particular those based on combined

cycle gas turbine technology. At the end of his chapter, R. Green examines

trends in gross and net investment (the latter accounts for the

decommissioning of old plants) and of the capacity margin in those two

countries, as well as in Finland, Norway, and Sweden. He particularly notes

two phenomena. First, the capacity margin is shrinking. This result is


consistent with the expected and desired results of the electricity system

reforms, in the sense that the previous regime was characterised by excess

capacity attributable to cost-plus regulation. Second, beyond a certain

threshold, the shrinking of the capacity margin serves as a trigger to

stimulate the resumption of investment. In his chapter, J.-M. Glachant also

draws attention to the shift in the energy mix toward gas-based electricity

generation. He measures and comments on it in the case of several U.S.

states, England, Italy, and Spain. This evolution is consistent with

developments in the relative performance of the different technologies, as

the total cost of combined cycle gas turbines has fallen below that of nuclear

technology.

The preceding economic model assumes that there is no uncertainty in

terms of demand.2 However, consumers’ reactions to price changes are very

poorly understood. Except in the case of certain large consumers, who

adjust their consumption to variations in the real-time prices on the spot

market or accept compensation for forgone consumption, information on the

price-sensitivity of demand is inadequate. Most consumers are not

confronted with hourly, or even daily, fluctuations in the price of electricity.

Their consumption is measured on a monthly or quarterly basis, and they are

charged a rate per KWh that is independent of the hourly distribution of

their consumption. Shielded thus from real-time price volatility, they have

no need to hedge against the risk of high prices. Furthermore, most domestic

consumers cannot be disconnected individually. And yet, there is no reason

to believe that residents of residential neighbourhoods will face the same

opportunity cost of not consuming. However, since they are all hooked into

the same distribution network, creating a market of interruptible contracts

cannot be readily envisaged. Consequently, there is no mechanism for

revealing households’ willingness to pay during peak hours.

Note that the underlying problem of short-term price-inelasticity of

demand did not originate with the opening of electricity systems to


competition. Under the previous arrangement, estimates of the value of

electricity lost in the event of a service interruption (Value of Loss Load, or

VOLL) were simulated by the planner in order to decide when generation

capacity needed to be boosted. When the cost of the new investment was

lower than the benefit of the averted service interruption - VOLL multiplied

by the reduction in risk of blackout attributable to the increased capacity

(Loss of Load Probability, or LLOP) - the investment was deemed

worthwhile. To fix an order of magnitude, if VOLL is 10,000€ per MWh,

then the public interest is served by the construction of a power plant that

will reduce the risk of interruption by approximately five hours over the

course of a year. Today, with electricity systems that are open to

competition, VOLL can also serve as a reference value. For example, during

critical periods, a systems operator may decide to purchase power at a price

equal to VOLL. In this event it is acting in the name of, and on behalf of,

consumers.

However, it is quite unusual for the regulatory authorities to authorise

such an astronomical price on the spot market, even during critical periods.

The very potential of prices to reach that level provides a powerful incentive

to generators to withdraw some capacity from the market so as to drive up

the price - i.e. to exercise their market power during periods of tensions

between supply and demand. Thus, for reasons of social acceptability and

market power, the spot price is often capped by regulation at a level far

below the VOLL. This type of intervention inevitably distorts the market

signal towards under-investment, and the plant with the shortest period of

operation during the year can no longer cover its fixed costs. The entire

cascading structure for covering the fixed costs of the various plants

collapses.

When real-time market prices are capped, undercutting investments, it

becomes necessary to invoke other instruments to provide economic agents

with a signal for the optimal capacity level. One elegant approach is based


on the notion that generators do not supply a single good, electricity, but

rather two goods, energy and capacity. The consumer values two services,

the power itself when she wants to watch television or turn on a light, and

also an option value for being able to do this at any time. From this

perspective, generators should be compensated for the capacity they supply

regardless of their utilisation. In practice, two systems have been

implemented: obligation capacity and capacity payments. In the former,

retailers (suppliers to the end-users) are obliged to maintain a capacity that

exceeds their expected peak load. To meet this requirement, they acquire

purchasing rights from generators on a capacity market created for that

purpose.3 In principle, the required capacity level must be determined by

comparing VOLL with the cost of the supplementary obligation capacity.

Provision must also be made to penalise retailers for failure to comply with

the mandatory supplementary capacities imposed on them. We observe that

this penalty establishes a de facto ceiling on the capacity market; retailers

will prefer paying it to buying capacity at a higher price. Consequently, the

amount of this fine must be linked to the cost to generators of making

capacity available. In the United States, the utility PJM has enforced this

type of obligation capacity market for several years. The required level

represents about 20 per cent of peak load and the penalty corresponds to the

fixed costs of a peaking plant ($7.4 per MWh).

During the 1990s, the English Pool established a capacity payments

system. Here, the compensation to generators for the capacity they supplied

was directly integrated into the electricity spot price. Unlike under the

previous system, there was no dedicated capacity market on which supply

and demand met directly. The capacity payment is also determined from

VOLL. In the case of England, it was set equal to VOLL minus the higher

of the station bid and marginal price (SMP), this difference being multiplied

by LOLP.

Whether the selected system is obligation capacity or capacity payments,


it is essential to bear in mind that the signals sent to investors originate at

least as much from public authorities as from private agents. On the side of

the invisible hand of the market: all the decentralised consumption and

generation decisions that propel the evolution of the price; on the side of the

visible hand of public intervention: identifying and setting the price cap and

calibrating VOLL. We shall see this hybridisation recur in the case of

investments in transmission.

4. Investment in transmission

Like other network infrastructures, electricity transmission grids present

technical and economic characteristics that are quite challenging from the

perspective of resource allocation. Like highways and airport runways,

electrical transmission lines are congested. As a result, use of this

infrastructure by one agent may degrade the quality of service available to

another. In economic jargon, this is known as a negative externality. In the

case of electricity, congestion may even result in the complete collapse of

the system. If the current is not cut, the lines may stretch and melt! Again,

like in the case of highway and airport infrastructures, investment occurs in

discrete units, leading to discontinuous jumps in capacity. To expand a

highway or an airport, a lane or a runway must be added in a single stroke.

Smaller, fractional investments are impossible. In electricity, the line type

for the high-voltage grid cannot be modulated by a single KV at a time. For

example, either 220 or 400 KV must be chosen. Similarly, the gauge of the

cable is not available in increments of a millimetre - the choice is limited.

These two technico-economic characteristics, congestion and

indivisibility (or lumpiness), are sometimes evoked in defence of misguided

concepts. First misconception: investment must proceed until congestion is

eliminated. In fact, if it were necessary to reinforce electricity transmission

lines to the point that their capacities would be able to carry any and all


transactions between generators and consumers at all times, the grid would

be bloated and astronomically expensive. If, during a single hour in one

year, a plant that is remote from a consumption zone is 10€ per MWh

cheaper than a local, more expensive generator, and if one MW of that

generation cannot be transmitted to the consumers because of an inadequate

line rating, then that line is congested during that hour. The cost of this

congestion is 10€ per year. Clearly, adding one MW of capacity to that line

would be much more expensive! Eliminating all congestion would only

make sense if grid construction costs were nil. Obviously, this is not the

case, and consequently the economically optimal level of congestion is not

zero. In fact, it is found at the point at which the cost of reinforcing the grid

is equal, at the margin, to the savings it makes possible, i.e. electricity that

can be bought from farther away at lower cost. The second misconception is

that investment should be undertaken as soon as the new line construction

project is profitable. It may, indeed, be preferable to wait and opt for a much

more profitable project later - one which will add far greater capacity at a

single stroke. S. Stoft uses a numerical example to illustrate how it could be

better to construct a 1000 MW line in two years than a 600 MW line today.

This is attributable to the lumpiness of the investment, which does not allow

demand growth to be matched by developments in generation in lockstep.

As with any infrastructure, it is worthwhile to distinguish between

efficient use of the network and efficient size of the network. In the first

case, capacity is treated as a given. Economic optimisation is thus a matter

of allocating its use to the economic agents who value it most highly. The

theory reveals that the key to accomplishing this lies in setting the access

price equal to the short-term marginal cost. In electricity, this cost has two

components. The first is due to ohmic losses that make it necessary to inject

more electricity than is withdrawn at the other end of the line. The second

component is congestion, which makes it impossible to replace local, high-

cost electricity with less expensive power from a more distant plant. Notice


that both of these elements of the marginal cost can be expressed as a

function of the price of the transmitted power itself, for example in €/kWh.

This allows us to establish an equivalence between the marginal cost of

transmission and the marginal cost of generation. Between two local

competitive markets, the equilibrium transmission price will equal the

difference in marginal production costs, so that a buyer will be indifferent

between buying from a seller who is closer but sells at a higher price and

one who is farther away and sells more cheaply. The energy pricing system

that corresponds to setting electricity transmission fees equal to the short-

term marginal cost is called nodal pricing, or marginal locational pricing.

These terms reflect the fact that the electricity price is different at each node

of the network. It also varies across time since demand, and by extension

congestion, fluctuates between the nodes. For example, the systems operator

of PJM (Pennsylvania-New Jersey-Maryland), the largest electricity market

in the United States, computes the price at the 3000 nodes several times per

hour. The issue of efficient network size is an issue of optimal investment.

The goal is to achieve the equilibrium size, i.e. expand capacity to the point

at which marginal cost rises above the benefit yielded by continuing. In

electricity, we have seen that this benefit amounts to displacing local

generation with more remote, cheaper generation.

The distinction between efficient use and efficient investment arises

because of a discrepancy between short-term and long-term marginal costs -

the former being lower than the latter - and between marginal and average

costs - the former again being the lower. These gaps are explicable in terms

of contingencies as well as by the presence of lumpiness and economies of

scale. For historical reasons, the current network is far from its optimal size.

As P. Joskow points out, the electricity transmission system we have

inherited today reflects historical institutional arrangements, the limits of

corporate activity, political boundaries, and historical patterns of urban and

industrial development. He states: ‘We can change the institutions but we


cannot erase the existing infrastructure in place at the time sector

liberalisation reforms are implemented but only change it gradually over

time.’ As a rule of thumb,4 networks that predate the competitive opening

are bloated. Governmental, and especially regulatory, intervention favoured

capital expenditures and provided for broad margins of safety to

accommodate growing demand and counter the risk of blackouts.

Furthermore, investment in tiers is incompatible with the notion that

installations erected for a 20 or 30 years lifespan can reflect the optimal

network size during each year. Inevitably, it will be under- or over-sized,

depending on the timing. Once again, over-investment wins out because of

economies of scale (i.e. the greater the investment in capacity, the lower the

cost of capital per unit of capacity).

The essential result of the realities described above and the discrepancies

they give rise to is that a price equal to the short-term marginal cost ensures

efficiency in use, but does not fully cover the investment expenditures

necessary to construct an optimally sized grid. In other words, the nodal

pricing system does not compensate the fixed costs of investments in

transmission. As I. Pérez-Arriaga and L. Olmos emphasise, ‘Cost recovery

by nodal prices typically does not exceed twenty per cent of total

transmission costs.’

This consequence keeps the market from operating efficiently. For P.

Joskow, ‘transmission networks do not and will not evolve through the

workings of the invisible hand of competitive markets.’ We note that, if

there were no gap between the short-term marginal cost and the average

cost, then a decentralised mechanism leading to an optimal level of

investment might have been feasible. Such a mechanism has been

conceptualised. The underlying principle is to allocate transmission rights

that yield congestion rents to the owners of each line as they are generated.

In his chapter, S. Stoft describes this mechanism - of which we have

provided a bare outline here - in detail, establishing the link between the


level of congestion rents, lumpiness, and economies of scale. Decentralised

investments in transmission lines (called merchant lines by convention) are

thus confined to modest growth. This conclusion recurs in the contributions

of P. Joskow, S. Stoft, and I. Pérez-Arriaga and L. Olmos. These authors

only envision merchant lines as a complement to investments regulated by

public bodies. To cite P. Joskow again: ‘Most transmission investment

projects are being developed today and will be developed in the future by

regulated entities’. Or, according to I. Pérez-Arriaga and L. Olmos:

‘Regulated investment must play a predominant role in the future

development of almost every real world transmission network.’

5. …and back to the coordination between investments in generation

and transmission

In a perfect world, in which demand reacts to the price of electricity and

competitive local markets are linked by incrementally extensible

transmission lines, the combination of nodal electricity prices and financial

transmission rights ensures a decentralised joint optimisation of investments

in generation and transmission. Prices exactly cover the costs of the efficient

mix, in terms of both the generation technologies and the distribution

between power lines and power plants. Consequently, from a theoretical

perspective, perfect coordination of investments in generation and

transmission in an electricity regime that is open to competition is not

impossible. The problem resides in the unrealistic nature of the assumptions

- all of which are needed to generate this result, however. Indeed, in our

imperfect electrical world, consumers’ willingness to pay is not known,

some generators possess market power, and transmission technologies

feature lumpiness and economies of scale. And yet, the theory is not ready

for the scrap yard. On the contrary, it suggests solutions for approaching the

optimum and minimising market failure.


In light of the failure of financial transmission rights to cover the fixed

costs of transmitting, other methods must be envisaged and implemented to

complement signals of short-term grid use with long-term signals to drive

investment. A first theoretical method is suggested by Y. Smeers. It is based

on designing a rate structure that captures several components. The

investment model he elaborates succeeds in inducing an optimal level and

location of generating capacity as well as in providing an incentive to the

TSO to efficiently manage congestion and develop infrastructure despite the

fact that investments are indivisible. Y. Smeers s draws on the work of

O’Neil et al. (2004) who expands the definition of goods, energy in our

case, to their spatial dimension. His model is more in keeping with the

institutional environment prevalent in Europe than that in the United States.

Network management is performed by an owner-operator of the

infrastructure who integrates dispatching, maintenance, and renewal of the

infrastructure. Unlike in the situation in which ownership and dispatching

are separated, here it is necessary to ensure that the system operator does not

curtail investments in order to increase revenues by creating congestion.

In the Y. Smeers model, the system operator receives instructions from

the regulator concerning how to set the long-term component of the price. It

also receives monetary transfers as an incentive to select an appropriate grid

configuration. The regulator is assumed to know electricity generators’

costs, consumers’ willingness to pay, and the set of possible network

configurations. Finally, markets are competitive and all agents - including

the systems operator- take prices as given.

The work of I. Pérez-Arriaga and L. Olmos also deals with pricing that

is based on several components, combines short- and long-term signals, and

covers fixed costs. However, their procedure takes a more operational

approach. Like Y. Smeers, they focus on the European context. A numerical

application of their model of long-term transmission costs has been

computed for all European grids. From a practical perspective, it allows


levels to be set for payments between system operators for use of the grid in

other Member Countries. We observe that the work of I. Pérez-Arriaga

and L. Olmos is more relevant to cost allocation than to optimisation. It can

be summarised as follows. To ensure that all transmission costs are covered,

a second component of revenues must be added to the fee structure based on

nodal electricity prices. Two cases can be distinguished. The first deals with

highly integrated networks: consumption centres and generation units are

more or less evenly distributed throughout the territory, and no systemic

congestion is foreseeable at any specific locations. In this case, there is no

need for localisation signals, especially since the beneficiaries of

investments in transmission would be difficult to identify and allocating

individualised costs and benefits impracticable. The other element of the

price, to cover fixed costs, must be computed by applying the Ramsey rule

(i.e. the size of the markup is inversely related to the consumer’s price

elasticity of demand). In the second scenario, the additional component

must capture as nearly as possible the costs and benefits to the grid of

decisions relating to the siting of the new plant or large energy consumer.

Among the several available algorithms that are based on some measure of

electricity use I. Pérez-Arriaga and L. Olmos recommend simple and

robust schemes that are based on the average network use and, in those

circumstances when it is essential to send to new network users signals

reflecting their responsibility on new network reinforcements, they propose

some new ideas on how to modify standard algorithms to achieve this

purpose.

P. Joskow emphasises the importance of consistency in the organisation

of energy markets and the institutions that govern transmission. ‘Organising

power markets and transmission institutions as if a clear separation exists

inevitably leads us to serious problems.’ He analyses two cases: one on each

side of the Atlantic. The aforementioned PJM is characterised by a systems

operator who does not own the grid. The grids are owned by electricity


utilities that are vertically integrated in generation, distribution, and

wholesale and retail operations. However, it is the PJM systems operator

who runs the day-ahead and balancing markets. It also operates the capacity

market. Load Serving Entities are, in fact, subject to capacity obligations

computed on the basis of their monthly peak requirements. As P. Joskow

explains, these supply requirements play an important role in the process of

investment in transmission and in providing siting incentives to generators.

The other case he examines is the Anglo-Welsh system. Until March of

2001, the wholesale market was organised into a mandatory pool.

Generators were compensated separately for power and for capacity. An

energy-only market followed with the implementation of the NETA (New

Electricity Trading Arrangements). We observe that the price on this market

is not capped. The systems operator, NGC, is integrated. It functions as the

systems operator, oversees maintenance of the grid, and makes the

investments. The transmission price is regulated by the Ofgem and includes

an element that depends on location. Generators in the north of the country

pay more than those in the south. In matters of investment, NGC is bound

by obligations specified in the network code and by various standards. To

comply with them, it conducts studies based on regional demand and supply

estimates. When a violation of a standard is identified, NGC determines

which investment projects should proceed. Their size determines whether

they require approval from the regulator. P. Joskow emphasises how well

the Anglo-Welsh system has performed since the mid-1990s. He considers

this to be the most successful experience in market liberalisation anywhere

in the world.

6. Overview of the book and synopsis of the contributions

In addition to this introductory chapter, the book consists of three parts.

Each of these comprises two chapters, where pure theory alternate with


practical application or empirical study. The first part (Chapters 2 and 3) is

devoted to investment in generation, while the second (Chapters 4 and 5)

addresses investment in transmission. The last part (Chapters 6 and 7)

examines the issue of coordination between investments in generation and

transmission.

R. Green’s contribution (Chapter 2) deals with the theoretical

mechanisms that determine the choice of the level and mix of electricity

generation capacity. A broad outline of these mechanisms was briefly

presented above. We shall underscore some of the contributions of this

chapter in more detail. R. Green reminds us that, in the final analysis,

investments in generation are not only about increasing capacity to satisfy

growing demand. Even with constant demand, new capacity is required to

replace plants that are inefficient - owing to technologically obsolescence -

and those that are at the end of their lifespan. It is just as important to

examine the economic determinants of plant decommissioning as of new

construction, especially since some plants can be mothballed before being

definitively shut down. They can be called on to meet exceptional needs.

We note that there is a certain parallelism between decommissioning an old

plant and commissioning a new one: both actions are irreversible. In the

presence of demand uncertainty, this implies that it may sometimes be

preferable to delay the decision rather than act immediately, since time may

yield better information. Thus, investment is triggered, not when the price

rises above marginal cost, but when it exceeds the marginal cost plus the

option value. Conversely, decommissioning of a plant occurs when the price

falls below marginal cost minus the option value. R. Green’s contribution

also discusses the cyclical character of investments in electricity generation.

He notes that, in contrast with other commodities, the possibility of keeping

plants in reserve and committing to long-term contracts should smooth the

cycles. These latter operate in two ways. First, they mitigate the uncertainty

facing entrants by allowing them to fix a price or a margin of their sales


price over the cost of fuel. Second, long-term contracts can function as a

sort of coordination mechanism for investments in generation - a

mechanism that is starkly lacking after the transition from a monopolistic to

a competitive market structure.

In Chapter 3, J.-M. Glachant presents a descriptive and applied

economic portrait of the changes to the technology mix induced by the

competitive opening. Did the reforms to the electricity sector have an

impact on the choice of generation technologies? Does competition create

new incentives that are biased towards certain technological developments?

Or, conversely, does competition marginalize certain technologies that

prospered in the context of a regulated industry? Drawing on extensive data,

J.-M. Glachant observes that, in the United States as in many European

countries, electricity reforms were accompanied by a technology shift

toward generation with combined cycle gas turbines. To a lesser extent, an

expansion of renewable energies can also be detected. On the other hand,

the construction of new nuclear reactors came to a halt and the amount of

electricity generated by this technology is declining. The conventional

explanation for this dual trend is as follows: liberalisation created

competition among technologies, allowing the efficiency of gas to come to

light, while the reforms also put an end to government subsidies to the

nuclear option. Rather than any simple intrinsic superiority of gas, or the

withdrawal of government support from research and development into

nuclear, J.-M. Glachant demonstrates that nuclear power is handicapped by

much higher capital costs than those of electricity generated from gas. This

differential is attributable to much greater financial risks associated with the

choice of nuclear technology. Construction costs and the operational

performance of these plants (particularly capacity availability and lifespan)

are imprecise and highly variable. J.-M. Glachant also reveals that capital

intensity, the size of the minimum unit of capacity, randomness in the

construction schedule owing to anti-nuclear mobilisation, and the absence of


any correlation between the price of the fuel and the price of electricity, are

all factors that increase the riskiness of the investment. According to a MIT

study that was extensively commented by J.-M. Glachant, this set of

factors gives gas an edge over nuclear in terms of the gearing rate (40 per

cent equity, versus 60 per cent for nuclear) and a lower yield requirement

for these funds (8 versus 15 per cent). As illustrated by the credit

arrangement of the Finish nuclear project TVO, the yield to investments in

nuclear power is undoubtedly to be found in long-term contracts between

generators and future buyers, reducing the risks and, by extension, the cost

of capital.

In Chapter 4, S. Stoft applies a pedagogical approach to elements of the

economic theory that shed light on investments in transmission and the

obstacles that undermine market efficiency. Here the reader will find

definitions of essential concepts, such as congestion (or redispatching) costs,

congestion rent, and the cost of congestion to load. These costs are

uncorrelated and should not be confused. S. Stoft also takes care to

distinguish between two concepts that are often linked because they both

underlie fixed costs and violate a basic assumption of the invisible hand of

the market; to wit, the convexity of the cost function. These concepts are

returns to scale and lumpiness. As a final pedagogical item, S. Stoft

debunks two misconceptions that are currently in vogue: it is not true that

the level of congestion should be reduced to zero; and it is not true that

market power is required to recover fixed costs. In his contribution, S. Stoft

compares three different approaches to investment in transmission: the

traditional planning approach, the merchant approach, and the performance-

based regulation approach. He discusses the last of these approaches at

length. Here the reader who is unfamiliar with the theory of incentives

applied to natural monopoly will find developments that shed light on the

underlying principles of the price-cap and on the dilemma confronting the

regulator seeking to encourage the systems operator to cut costs while not


leaving an excessively high rent that will penalise consumers. S. Stoft

points out two major difficulties associated with establishing incentive

regulation in the case of the electricity transmission grid. The first is linked

to the length of the delay in benefits accruing to the investor. The timeframe

of these investments may, in fact, look as follows: considerable sums must

be committed over several years, which are followed by several more years

during which the return is nil, or minimal, and only ten or fifteen years after

the beginning of the project does it truly begin to pay off. The second

difficulty arises from the tight linkage between the investment and security

of supply (reliability). In the United States, most of the major blackouts that

occurred during the past 35 years were attributable to problems with

transmission rather than generation. In light of this, regularly pruning trees

growing beside power lines, updating computer systems, and installing line-

trip relays are all essential. Thus, incentive mechanisms that cover activities

other than the construction or reinforcement of power lines are needed. In

the words of S. Stoft, ‘Performance Based Regulation for Transcos will be

useful for shorter term incentives, but it also cannot be relied on to solve the

long-term investment problems.’ Since the development of merchant lines is

bound to be constrained by issues surrounding the recovery of fixed costs,

as we saw above, there is, in the final analysis, no alternative for

government authorities but to pursue traditional regulation.

In Chapter 5, P. Joskow sketches out, in some detail, the various existing

institutional arrangements that govern operation of the grid, inform the

regulatory framework, and provide incentives to invest in transmission. He

demonstrates how these arrangements depend on the historical, economic,

and physical characteristics of the network and examines their performance.

P. Joskow’s contribution is too rich to be summarised here. For example, it

contains an exhaustive list of the various components of the network that

play a role in reinforcing its capacity. Economic models tend to focus too

exclusively on the construction of new lines, for there are many other ways


to reinforce a network. Too illustrate, from P. Joskow’s list: new relays and

switches, reconductoring existing lines, and new remote monitoring and

control equipment. He also proposes a classification system for different

types of investment and discusses it in detail. We also draw your attention to

two original observations by P. Joskow. The first pertains to the gulf

between the viewpoints of economists and engineers on the subject of

investments in transmission. The models of the former have little in

common with the manner in which investments in transmission are actually

programmed and developed, or in how the associated services are priced.

They do not account for the engineering reliability criteria on which

engineers base decisions to reinforce a network. Of course, there cannot be

two disjoint types of investment, one based on economic calculations and

the other on reliability. P. Joskow vigorously argues that these two

approaches need to be reconciled. The second observation concerns his

distinction between inter- and intra-SO transmission grid investments. Each

TSO will first tend to deal with congestion issues on its own grid

independently, and then facilitate residual economic exchanges with other

grids. This policy results in congestion being pushed across borders and in

reduced economic efficiency. P. Joskow suggests that inter-TSO investment

opportunities can be addressed more effectively through interconnected

zones using the same reliability criteria and standards of evaluation, as well

as by integrating wholesale markets and harmonising pricing practices

across countries. He strongly recommends the creation of regional

transmission operators.

Y. Smeers’ Chapter 6 addresses a knotty and so-far unsolved problem -

finding price signals that will motivate systems operators to invest optimally

and allow them to recover their costs. In other words, is it possible to

decentralise investment decisions when they are lumpy? The solution

suggested by Y. Smeers is a price comprised of several components and

incorporating access and congestion fees. The reader unfamiliar with


optimisation models, in particular nonlinear models, may benefit from

reading the introduction (Sections 1 and 2) and the discussion (Sections 8

and 9) of this chapter, where the author’s approach and results are

summarised in a non-technical manner. One result that merits comment here

deals with European regulation of interconnections. It stipulates that rates

must comply with three principles: economic efficiency, cost causality, and

non-discrimination. Y. Smeers begins by building a model with no linkage

between agents’ localisation decisions and the structure of the network.

Thus, his model does nor respect the principle of cost causality.

Nevertheless, the proposed price structure is efficient because it is based on

price discrimination. It is well-known in economics that price discrimination

provides an economically optimal way for fixed costs to be recovered. Next,

Y. Smeers introduces cost causality, which allows discrimination to be

reduced but not eliminated. This can be accomplished without endangering

the balanced budget of the system operator, but only at the cost of partially

sacrificing the goal of economic efficiency. The prohibition on price

discrimination must be juxtaposed with the loss of social surplus it entails.

When subsidies to investments in interconnections are precluded, an

arbitrage between the allowed level of discrimination and the tolerable

amount of economic loss becomes necessary. Nothing in the European texts

or discussions provides for this arbitrage.

In Chapter 7, I. Pérez-Arriaga and L. Olmos address the same issue as

Y. Smeers, long-term siting signals and covering the fixed costs of

transmission networks. They, however, take a different approach - their

perspective is practical and their process operational. This compels them to

make certain concessions, notably in adopting cost-allocation methods that

sometimes owe more to accounting than to economics, and also in

simplifying the physical functioning of the grid. Their contribution nicely

rounds out the preceding contributions. Besides, they examine how

locational signals that are derived from the existence of the transmission


network – differences in energy prices due to losses and congestions, plus

transmission charges with locational differentiation – compare numerically

among themselves and also with other non electrical locational signals, such

as potential charges for the use of gas infrastructures or differences in the

efficiency of thermal power plants beause of the altitude over sea level.

It is recognized that the agents who make the decisions on transmission

investments strongly depend on the specific regulatory paradigm that is

adopted in each country : System Operators, regulators, coalitions of

network users and merchant investors - alone or in different combinations -

can be the responsible parties. Accordingly, the economic signals that may

provide incentives to make correct decisions on new transmission

investments depend of the adopted regulatory paradigm. Although all the

considered paradigms are useful ones, not all of them would result in a well

developed network.

Under a competitive regulatory framework it is essential for the

successful development of both generation and transmission to minimize the

uncertainty that the decisions of generators create for the network planner

and, conversely, that complete and reliable estimates of future transmission

conditions be facilitated to generators by the System Operator. Several

regulatory instruments can be applied to reduce the unavoidable level of

uncertainty that surrounds the decision making process of generators and

transmission planners.

I. Pérez-Arriaga and L. Olmos remind us that there is more to the

electricity network than the high-voltage transmission grid. The structure

and renewal of the distribution grid must also be considered. However, these

two components of transmission fulfill different functions. Consequently,

regulatory approaches and investment criteria must differ as well. A series

of practical considerations are proposed in this contribution in order to

ensure compatibility of signals for investments in transmission and

distribution.


7. Conclusion

After having read this introductory chapter, the reader may be amazed at the

length of the road to be travelled on the way to ideal investment conditions.

It should not be forgotten that this difficult task springs from a very

ambitious goal. Investment is an issue of dynamic economics. This is more

complicated than problems of static efficiency, and the corresponding

economic tools are less robust. Moreover, in this case the duration of

investments is measured, not in years, but in decades. Seeking to know the

optimal generating and transmission capacity of the electricity system is no

less ambitious than attempting to build the cities of tomorrow and design the

network of highways and byways that will link them. We must accept that

the ideal of an electrical utopia will elude us, but instead we can elaborate

principles of urban and land-use planning that will make decentralised

decisions more efficient. Such is the hope of this undertaking.

Notes

1 Notice that application of this idealised rule not only runs up against the opportunism of

generators. It also assumes that the SO (or the competent regulator) acts in the public

interest, is able to forecast future energy demand, and is able to precisely define the

optimal level of capacity (i.e. the number, type, and location of plants) and the grid

configuration that will satisfy that demand efficiently.2 It also assumes risk-neutrality of investors. Risk aversion leads to under-investment in

peaking plants - some of which are only profitable, in principle, if they operate several

hours per year on average.3 If they are vertically integrated, they can arrange this supply internally.4 With the notable exception of interconnections between countries. In Europe, these

were built for security rather than business considerations. The opening to competition


and burgeoning trade soon made their inadequacy clear.

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