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
20 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 21
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
22 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 23
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
24 Competitive Electricity Markets and Sustainability
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,
Investments in competitive electricity markets: an overview 25
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
26 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 27
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
28 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 29
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.
30 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 31
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
32 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 33
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
34 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 35
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
36 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 37
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
38 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 39
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.
40 Competitive Electricity Markets and Sustainability
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
Investments in competitive electricity markets: an overview 41
and burgeoning trade soon made their inadequacy clear.