Generation adequacy: Helping the market do its job

Utilities Policy 15 (2007) 20e35 www.elsevier.com/locate/jup

Generation adequacy: Helping the market do its job Laurens J. De Vries* Delft University of Technology, Jaffalaan 5, 2628 BX Delft, The Netherlands Received 16 January 2005; received in revised form 14 August 2006; accepted 15 August 2006

Abstract In response to concerns that competitive electricity markets may be subject to the development of an investment cycle, a number of adjustments to the market structure have been proposed for stabilizing investment in generating capacity. This paper reviews the advantages and disadvantages of these capacity mechanisms and presents a policy framework for selecting the most suitable capacity mechanism. The choice of capacity mechanism depends upon circumstances such as whether the market in question has a mandatory power pool and whether it is strongly interconnected to other markets. This analysis focuses specifically upon options for European markets, which typically are of the decentralized type (without mandatory power pools) and have significant exchanges with neighboring markets. These two factors complicate the implementation of a capacity mechanism. Ó 2006 Elsevier Ltd. All rights reserved. Keywords: Electricity; Generation, Investment; Regulation; Capacity mechanism

1. Introduction In this paper, a policy framework is developed for analyzing policy options for maintaining generation adequacy in competitive electricity markets. Concerns whether competitive electricity markets provide a sufficiently strong and early enough investment signal rose after the crisis in California’s electricity market in 2000 and 2001 (cf. Turvey, 2003). Shortages in other places, such as in New Zealand, Scandinavia and Italy, have fueled these concerns. A number of adjustments to the market structure have been proposed with the purpose of stabilizing the volume of generating capacity. A systematic framework for the selection of such a capacity mechanism has not yet been developed, however.1 The focus of this paper is on Europe, because European electricity markets have several specific features. First, most European markets are of the decentralized kind, in Hunt’s * Tel.: þ31 (0)15 278 1137; fax: þ31 (0)15 278 3422. E-mail address: [email protected] 1 An earlier version of this paper was presented at the 19th World Energy Congress and Exhibition (Sydney, 5e9 September 2004). 0957-1787/$ - see front matter Ó 2006 Elsevier Ltd. All rights reserved. doi:10.1016/j.jup.2006.08.001

(2002) typology. This means that they do not have a mandatory power pool, but that market parties may trade their electricity bilaterally and only need to notify the system operator of their physical programs. In integrated markets, on the other hand, all physical trade takes place through a mandatory pool (such as the PJM pool), and bilateral contracts can only be financial. Second, many European markets have significant trade volumes with neighboring markets, while the connected market models often vary greatly. Third, hydropower plays a limited role in most European markets, the exceptions being Scandinavia and the Alp countries. This means that most European power markets are capacity-constrained, rather than energy-constrained. Capacity mechanisms vary widely in the way they work and with respect to their implementation requirements. Some provide financial incentives to generating companies, while others control the volume of generating capacity. Some are designed for mandatory pools, which means they might need to be adjusted for implementation in decentralized markets. Except in PJM, little attention has been given to the issue of trade between electricity systems: how to prevent the investment incentive from ‘leaking’ to neighboring electricity systems, and how

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2. Why a capacity mechanism? 2.1. Unmanageable risks There are several reasons why energy-only electricity markets may not provide a sufficient incentive to invest in generating capacity in a timely manner.2 Here we will provide a synopsis; a more extensive argument can be found in De Vries and Hakvoort (2003) and in De Vries (2004). The high volatility of electricity prices (especially in markets without much hydropower), the capital-intensive nature of generation and the long lead time of new facilities together cause investment risk to be high. If investors are risk-neutral and have all the necessary information, this should not matter and the volume of generating capacity should still be socially optimal, at least in a perfectly competitive market (cf. Caramanis, 1982; Stoft, 2002). Generating companies would invest up to the point where their expected long-run average returns would equal the long-run marginal cost of generation. However, it is difficult to estimate future generator revenues, because they depend strongly upon the frequency, height and duration of price spikes. Consider for example the pricee duration curve of the Dutch APX spot market in Fig. 1. (The figure actually only shows the lower part of the priceeduration curve. Prices actually rose to 2000 V/MWh during a very small number of hours.) From the data underlying the graph, it might be concluded that prices above 100 V/MWh occur about 4% of the time. However, the curve is very steep at this point, which means that small changes in the occurrence of price spikes may greatly impact the shape of the loade duration curve in this area. Consequently, it is risky to estimate the profitability of a peaking unit based upon this data. 2 An ‘energy-only market’ is defined as an electricity market in which there are no specific provisions to stimulate investment in generating capacity (Doorman, 2000). Consequently, generating companies base their investment decisions upon their expectation of future prices for electric energy.

500

Hourly price (€/MWh)

to make a capacity mechanism resistant to regional shortages? This paper develops a set of criteria for evaluating the different proposed capacity mechanisms, describes the advantages and disadvantages of the different capacity mechanisms and, most importantly, develops a framework for deciding which capacity mechanism to implement under which circumstances. The next section starts with a brief summary of the reasons for implementing a capacity mechanism. Section 3 develops a set of performance criteria which capacity mechanisms should meet. This set is used to evaluate proposed and actual capacity mechanisms in Section 4. However, none of the currently proposed capacity mechanisms appears satisfactory for implementation in a market without a mandatory pool but with interconnections, such as many European systems. Therefore Section 4.6 proposes an innovative version of the capacity mechanism called reliability contracts. Section 5 contains the second part of this paper, which is devoted to the development of a policy framework for the selection of a capacity mechanism.

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Duration (percentage of time) Fig. 1. Priceeduration curve of the Dutch APX spot market, 1999e2004 (source: http://www.apx.nl).

Most liberalized electricity markets are still in a transition phase, so historical data are not a good basis for projecting such volatile revenues in the future. For instance, Europe started liberalization with ample reserve capacity, as a result of which electricity prices were relatively low during the first years of liberalization. In the summer of 2003, however, prices rose to unprecedented heights in a number of European countries. A tightening supply of generating capacity is forecast for Europe towards the end of the decade (UCTE, 2005a). As a result, more price spikes may be expected and average prices may continue their current rise.3 When, or to what degree, remains uncertain as it depends on how much new plant will be built in the mean time and on the development of demand. Without long-term contracts, it is therefore difficult for generating companies to forecast their revenues. Several causes of regulatory uncertainty may further reduce the ability of generating companies to forecast their revenues. One example is the risk to generating companies that government may intervene in the electricity market, for instance by imposing a (lower than existing) price cap in response to a price spike. Changes in related markets, such as emissions trading schemes and restructuring of primary fuels markets also create uncertainty with respect to future generator returns. Gas prices are fundamentally uncertain, as they are linked to oil prices. The halting restructuring process of European gas markets, which wavers between the desire to create competitive markets and supporting large European companies who have significant buying power in negotiations with gas exporting countries, adds further risk to investment in electricity generating capacity. With respect to the trade of CO2 emissions credits in Europe, a fundamental obstacle is the fact that the Kyoto period will end in 2012. There is no indication whatsoever of what will follow: whether there will be some kind of continuation of the tradable emissions scheme, other

3 Ceteris paribus. Of course, primary fuel prices have a significant influence upon electricity prices. The actual issue is the spark spread, the price difference between the electricity price and the price of fuel. However, for the sake of simplicity we will refer to the electricity price.

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emissions regulations or nothing at all, let alone that there is any clarity about the abatement levels that will be required. This poses a fundamental obstacle to investors in power plants in Europe, as their new plants will exist (nearly) entirely after the Kyoto ratification period. 2.2. Asymmetric loss of welfare functions Stoft (2002) shows that in theory, the optimal volume of generating capacity can be determined from the average value of lost load and the long-run marginal cost of generation. However, estimating the average value of lost load is notoriously difficult (cf. Kariuki and Allan, 1996a,b; Willis and Garrod, 1997; Ajodhia et al., 2002), which means that this calculation is likely to be inaccurate. Moreover, more relevant than the currently optimal volume of generating capacity is the optimal volume at the time that new capacity would come on stream, several years into the future. Considering the inherent difficulties in estimating the optimal volume of generating capacity and the substantial investment risks that were described in the previous paragraph, a more relevant question is what the costs are of erring, that is, of the volume of generating capacity not being optimal. The costs depend upon the perspective: investors have a different interest than consumers. For generating companies, investing in excess of the socially optimal volume of generating capacity means that competitive prices will be too low to recover their investment, while a volume of generating capacity that is below the social optimum leads to significantly higher average prices, which offset the lost turnover at least partly. Therefore it is to be expected that especially in markets that are less than perfectly competitive (as electricity markets generally are), generating companies would be somewhat risk-averse in their investment decisions (Neuhoff and De Vries, 2004). The presence of significant entry barriers would facilitate a strategy of tight investment. Like investors, consumers face an asymmetric loss of welfare function with respect to the socially optimal volume of generating capacity, but one that is opposite. During the crisis in California in 2000 and 2001, at most 2% of load was shed at any time (Hawkins, 2001), but the costs to consumers were extremely high (Weare, 2003). The costs of excess investment, on the other hand, appear much more limited. Shuttleworth et al. (2002) calculate that if the economically optimal reserve margin were 8% of installed capacity, and the reserve margin somehow was established at 20%, the associated social cost would be about 1.1% of the retail price of electricity. Therefore we may draw the conclusion that the provision of electricity is characterized by a strongly asymmetric loss of welfare function. This result is corroborated by Billinton et al., (1991), who show a strongly asymmetric loss of welfare function. 2.3. Investment cycles High price volatility, long lead times, imperfect foresight, regulatory uncertainty and risk aversion are reasons for generating companies to delay investment until the need for new

generating capacity becomes reasonably certain. Due to the low price elasticity of demand and the relative ‘flatness’ of supply curves, prices do not rise significantly in a competitive electricity market until the margin between available generating capacity and peak demand becomes small. Due to the long lead time before new generating capacity can be taken into operation, this margin is likely to decrease further and may even disappear before new capacity is available. Depending on the growth rate of demand, investment in reaction to price rises may not arrive soon enough to prevent a significant period of shortages. The high prices that would develop in the mean time could trigger an over-reaction by investors, after which a period of excess generating capacity could lead to prices below the long-run marginal cost of generation. Like some other capital-intensive industries, the electricity generation industry appears prone to investment cycles. The theoretical arguments why insufficient investment may be expected appear to be corroborated by the UCTE (2005a), who forecasts declining capacity margins in mainland Europe towards the end of the current decade. Long-term contracts are the common solution to the above problems of investment risk and possible cycles. However, in electricity markets they do not develop to a sufficient degree. An important reason is that consumers can free-ride on each other, because reliability is a public good (Neuhoff and De Vries, 2004). Therefore it is unattractive to consumers to engage in long-term contracts when the short-term electricity price is below the long-run marginal cost. Second, consumers probably do not have the time horizon, especially during a period of excess capacity, or sufficient knowledge, to be willing to enter into contracts at a price near the long-run marginal cost of generation that have a duration that is sufficiently long to attract investment (Va´zquez et al., 2002). Finally, the market for forward contracts is inevitably characterized by a low liquidity. The fact that electricity prices vary in the course of the day means that there is a need for separate forward markets for each of the markets time periods (typically between 5 minutes and half an hour, depending on the conventions of the market at hand) (Aalbers and Baarsma, 2005). Alternatively, more complex contracts with different profiles, such as for residential consumption, ‘flat’ industrial consumption and so on could be developed. However, then separate sub-markets for these profiles would develop, still not solving the liquidity issue. Given uncertainty about the optimal volume of generating capacitydespecially as many years in advance as it takes to construct new generating capacitydthe risk asymmetry is reason for consumers to err on the side of more generating capacity. However, we saw that cautious investors would tend to provide less generating capacity than the theoretical optimum, and that even without risk-averse investment there is a possible tendency towards investment cycles. Therefore it is in the interest of consumers to implement a mechanism in order to ensure a certain volume of generating capacity, especially because the cost of accidentally investing too much is relatively small. Precisely how much generating capacity should be maintained remains an issue for discussion. However, even if the

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implementation of a capacity mechanism led to a limited volume of excess capacity (beyond the economic optimum), this would be preferable to consumers over occasional periods with an under supply of generating capacity. This is not a new argument (cf. Cazalet et al., 1978), but one that is often overlooked in the design of liberalized electricity markets. 2.4. Market power during periods of scarcity A third reason to change the market structure is that price spikes, which should provide the investment incentive in an energy-only market, can be manipulated if the price-elasticity of demand is limited (as it is in most existing electricity markets). By offering less generating capacity to the market, generating companies may be able to increase the electricity price substantially (Newbery, 2001; Stoft, 2002; Joskow and Kahn, 2002). This has several consequences. First, it leads to substantial income transfers from consumers to generators, as we saw in California. Second, it may undermine reliability. Third, if it becomes unclear whether price spikes are a true indication of scarcity or instead the result of the exercise of market power, price spikes lose their function as indicator of the need to invest in new capacity. A larger reserve margin, as could be created with a capacity mechanism, would substantially reduce this kind of market power. 2.5. Other considerations Capacity mechanisms have two main disadvantages. First, any change of market structure entails a risk of regulatory failure. Specifically, trying to influence the volume of generating capacity carries a risk of creating new avenues for the exercise of market power by withholding generating capacity, because the supply of generating capacity is highly inelastic in the short term. When designing a capacity mechanism, careful attention must therefore be given to the incentives to generating companies that develop when capacity is tight. The second disadvantage is that a capacity mechanism may lead to a sub-optimal volume of generating capacity. This risk must be weighed against the risk of under-investment. Considering the asymmetric loss of welfare function, the social costs of a modest level of excess capacity probably are small. Capacity mechanisms may have additional benefits, too. The main benefit, in addition to minimizing the risk of shortages, probably is the reduction of generator market power. Another advantage is that if a capacity mechanism reduces investment risk, for instance by making the demand for generating capacity more explicit or by stabilizing generator revenues, the cost of capital may become lower. Reducing price volatility also is an important advantage to consumers, who generally cannot hedge themselves sufficiently against price spikes. A final caveat, before we start the evaluation of capacity mechanisms, is that this analysis is based upon the assumption that generating companies compete with respect to price. It is not necessary to assume perfect competition (in fact, the prevalence of market power is an important consideration in the design of a capacity mechanism), but if there is no effective price

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competition, the analysis does not hold. If generating companies do not compete on price, they may be able to keep the price high enough to allow them to maintain a sufficient generation margin. They might be interested in doing so to avoid the political attention that develops during a shortage. A second reason is that the presence of excess generating capacity would deter new market entrants (Tirole, 1988). The following analysis is based upon the assumption that the policy of liberalizing electricity markets is effective with respect to creating competitive markets. 3. Performance criteria The previous section presented reasons for competitive electricity markets to include a capacity mechanism as part of the market design. We may conclude from this analysis that the main goals for a capacity mechanism are to provide incentives to generating companies to provide an adequate volume of generating capacity, even in the presence of imperfect information, regulatory risk and/or risk-averse investor behavior. Second, the incentives for withholding generating capacity during a shortage should be removed; rather, generating companies should receive incentives to maximize their output during shortages. And of course, a capacity mechanism should not introduce new opportunities for the exercise of market power. A less universally supported goal is to stabilize prices. This goal is controversial, as in the theoretically optimal model of electricity markets, prices should be allowed to rise up to the average value of lost load in order to provide efficient operational incentives (including demand response) and efficient investment incentives (cf. Caramanis, 1982; Stoft, 2002). However, both consumers and generating companies are negatively affected by the limited opportunities for hedging price risk through long-term contracts. For generating companies, it means that they probably will choose to invest less, in the aggregate, than if they could have covered their investment risk with long-term contracts. While the presence of a capacity mechanism may correct for underinvestment, consumers also wish to reduce their price risk, even if the volume of generating capacity were optimal. The welfare loss that consumers experience when electricity is scarce is not so much due to the loss of service, if this occurs, but mostly to the (much longer) period of high prices that accompanies it. The California crisis is illustrative: the frequency and duration of electricity service interruptions (rolling black-outs) was modest, but the cost to consumers was very high.4 In the absence of instruments for hedging their price risk, the risks may be unmanageable for many consumers. Therefore it may be argued that another goal for a capacity mechanismdperhaps more important than reliability of service itselfdis to stabilize prices.

4

In this case, most consumers did not pay directly for the high prices, but indirectly through their taxes, to pay for the state government’s interventions to maintain the supply of power.

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In open electricity markets (markets with a significant volume of trade with neighboring electricity markets), compatibility issues arise when neighboring systems do not implement a capacity mechanism or a different one. This situation may develop in the European Union, where the issue of generation adequacy is left to the member states (Directive 2003/54/EC), following the general principle of subsidiarity. If a capacity mechanism improves generator revenues by raising off-peak prices, for instance, this effect may ‘leak’ to neighboring systems to the degree that demand is met through imports. During a regional shortage, these imports may not be available. To be robust, a capacity mechanism should provide incentives for developing generating capacity within the system in which the capacity mechanism is implemented. Generation capacity in neighboring systems could be included to the extent that they can prove that they have access to sufficient transmission capacity and can commit their output. Similarly, a capacity mechanism should provide a means for ensuring that the generating capacity that it supports is available to those who finance it. This means that if a country implements a capacity mechanism, its benefits such as improved reliability and more stable prices should accrue to the consumers in that country. Thus in an open market, a capacity mechanism must provide a means for ensuring that during a regional shortage, arbitrage between neighboring countries does not undermine the benefits (in terms of reliability and lower prices) of the capacity mechanism. Without such a provision, the capacity mechanism would be practically ineffective, with consumers paying for extra generating capacity, the benefits of which would be exported. Finally, there are some more general goals for capacity mechanisms. Improved price-elasticity of demand would reduce the volatility of electricity prices and hence investment risk. It would also reduce the probability of service interruptions during shortages. Therefore policy intervention for the sake of securing generation adequacy should also stimulate the development of demand price-elasticity. Supply-side efficiency also is a general goal for market design: the capacity mechanism should not distort generating companies’ investment decisions (with respect to the size or type of generator) or dispatch decisions. Finally, any adjustment to the market structure should be feasible. In the case of Europe, this means that it should be compatible with decentralized, open markets and the European legal framework. With respect to the latter issue, Knops (2002) concluded that there is enough room, in legal terms, for EU member states to develop their own capacity mechanism. (Whether it is a good idea that each develops its own model is a different issue.) Summarizing, capacity mechanisms should ideally meet the following criteria:  incentives to generating companies to provide an adequate volume of generating capacity  incentives to generating companies to maximize output during a shortage  no new opportunities to exercise market power  stabilization of prices

    

effectiveness in an open market robustness against a regional shortage stimulation of demand price-elasticity supply-side efficiency physical and institutional feasibility

De Vries and Hakvoort (2003) presented an overview of capacity mechanisms. In the next section they are described briefly and evaluated. To keep the discussion of the capacity mechanisms concise, not every criterion is discussed in each case. Instead, for capacity mechanisms with significant shortcomings the discussion is limited to these shortcomings. 4. Capacity mechanisms 4.1. Capacity payments Several capacity mechanisms have been implemented or proposed. Capacity payments, one of the oldest solutions, are or were used in for instance Columbia, Spain and Argentina (Va´zquez et al., 2002). Essentially, a capacity payment is a subsidy per unit of (available) generating capacity. The idea of capacity payments is that by reducing the fixed cost of generation, the long-run market equilibrium will shift towards a larger volume of generating capacity. Capacity payments are often made in compensation for an electricity price cap, which would otherwise probably lead to insufficient investment. Typically, capacity payments are extended to all generating units, for reasons of fairness, in order not to distort competition and to stimulate generating companies to delay the decommissioning of old units. In their most basic form, a capacity payment is a simple subsidy that is not accompanied by an obligation on the part of the generating companies, for instance with respect to availability. Such obligations could be added, in which case the scheme may evolve in the direction of reliability options (below). The effectiveness of capacity payments is doubtful because of two fundamental weaknesses: the absence of obligations on the part of generating companies in exchange for the payments and the indirect effect upon investment and hence reliability. Consequently, it is unclear what benefits consumersdwho in the end are the ones who finance the paymentsdderive from them. The payments may not necessarily suppress the tendency towards investment cycles. While they reduce investment risk, they do not provide a clearer indication of the total demand for generating capacity than an energy-only market does. In addition, it is nearly impossible to determine the optimal level of the payments (Va´zquez et al., 2002). Because the demand curve for generating capacity has a steep slope and the supply curve has a gentle slope, a small deviation in the payments leads to a large shift in the equilibrium volume of generating capacity. This is the ‘classic prices versus quantities argument’ (Weitzman, 1974; see also Oren, 2000). This argument also holds for the other price-based capacity mechanisms, a strategic reserve and operating reserves pricing: given the many uncertainties regarding the relation between market prices and investment behavior, it is more difficult to

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obtain a desired level of reliability through a financial incentive than by controlling the volume of generating capacity directly. The quantity-based capacity mechanisms (capacity requirements, reliability contracts and capacity subscriptions, discussed below) are more effective but also more complicated. Advantages of capacity payments are that they can be combined with a price cap, so they improve price stability, and that they are easy to implement. 4.2. Strategic reserve Another relatively simple option is for the system operator to acquire a strategic reserve (sometimes also called a mothball reserve or a ring-fenced reserve) of power plants that are used only in emergencies. In the Netherlands, a detailed proposal has been developed and approved for implementation if the reserve margin becomes too small (TenneT, 2005). The idea is that purchasing or leasing (in the case of the Netherlands) a certain volume of capacity, in addition to existing operating reserves, will tighten the electricity market and thus lead to new investment, presumably replacing all the generating capacity that has been contracted by the system operator. After some time, the volume of available generating capacity should therefore be the same as before the strategic reserve was contracted, while the system operator now has a larger reserve. If the market equilibrium of generating capacity proves to be too small, the system operator can now use its extra reserves to avoid physical shortages. Because the investment signal depends on the scarcity prices that result from taking a certain volume of generating capacity out of the market, this measure may be considered a price-based capacity mechanism. For generating companies, the scheme has the following incentives. First, it provides for keeping old units operational, because they can be sold or leased to the system operator. This incentive consists solely of the revenues to the generating companies from leasing or selling the reserve units; when these reserve units are dispatched, the system operator collects the operating profits. Second, withdrawing a certain amount of capacity from the market should provide an incentive to replace this capacity. However, this incentive depends on the price for which the reserve capacity is dispatched. When the reserves are deployed, the price for which the electricity that they produce is sold will effectively cap the market price (until no more reserve capacity is available). The Dutch model is to dispatch the reserve at above-market prices, lest it would deter investment (TenneT, 2005). A choice can be made to dispatch the reserve at lower prices, which would dampen the price volatility, but then the reserve must be larger in order to compensate for the reduction of the investment incentive. The difficulty with a strategic reserve (and with operating reserves pricing, the next capacity mechanism that we discuss), is how to calculate the correct combination of reserve volume and dispatch price. As with all capacity mechanisms except capacity subscriptions (see Section 4.7), the regulator first must determine the optimal volume of generating capacity. Then he must decide how large the strategic reserve will be. In case the reserve will be dispatched at above-market

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prices (e.g. near the average value of lost load), the reserve must make up the difference between the expected volume of generating capacity that the market will provide and the optimal volume. But how can either figure be determined with any certainty? In case the reserve is dispatched at lower prices, the effect of reducing price spikes upon the investment incentive must also be included. In principle, given accurate loadeduration data, it can be estimated how much time the marginal competitive generator (i.e., the most expensive generator that is provided by a competitive firm) will operate on average. With an estimate of the costs of this generator, the correct dispatch price for the strategic reserve can be determined. The dispatch price should be such that this marginal generator just can recover its full costs. With the loadeduration curve, it can then be determined how large the reserve must be to make up the difference between the volume of generating capacity provided by competitive generating firms and the desired volume of generating capacity. However, it remains difficult to make those estimates, because the necessary data is usually not available with enough accuracy. The possibility of an investment cycle further complicates matters. Calculation errors will either lead to an under incentive for investment or to electricity prices that are, on average, higher than necessary to fund the necessary generating capacity. A strategic reserve is a modification of an energy-only market: investment is still driven by price spikes, but reliability is enhanced through an extra volume of generating capacity in the reserve. This means that the same tendency exists towards investment cycles, although a large reserve may reduce this tendency. Similarly, the incentive for withholding generating capacity remains unmitigated until the electricity price has been reached at which the reserve is dispatched (at which point any withheld generating capacity is replaced by capacity from the reserve). Finally, the higher the dispatch price, the smaller the effect upon price volatility. As high prices are the main cause of consumer welfare loss, a strategic reserve only addresses part of the problem at best. Thus, in choosing the size of the reserve, there is a trade-off to be made. Selling the reserve capacity at above-market prices minimizes the distortion of investment incentives, but also leaves price volatility and market power unmitigated. A larger reserve on the other hand, dispatched at a lower price would mean that the reserve operator will become a major party in the generation market. This may not be desirable with respect to his independence or the efficiency of generation investment and dispatch. An issue in individual European countries is that a strategic reserve is not robust against regional electricity shortages in an open, decentralized market. If consumers pay for a strategic reserve, for instance through a fee that is added to the electricity price, they would expect the benefit of improved reliability of service. However, in an open, decentralized market, scarcity in a neighboring system will also lead to high prices in the system at hand. If there is sufficient interconnector capacity, trade between the two systems will cause the prices and the reserve margin to be about the same in the two systems. Thus the effectiveness of a strategic reserve is limited.

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4.3. Operating reserves pricing

4.4. Capacity requirements

Similar issues trouble the proposal for operating reserves pricing (Stoft, 2002). In this capacity mechanism, the system operator contracts a volume of reserve capacity through daily auctions. This reserve capacity is contracted in addition to the regular operating reserves. The system operator exhibits a limited maximum willingness to pay for the reserve capacity. This effectively caps the market price: when the spot electricity price exceeds the system operator’s willingness to pay, generating companies will find it more attractive to sell to the spot market electricity generated with the capacity that they usually sell to the system operator. The consequence is that the system operator’s additional demand for generating capacity will cause prices to rise sooner than otherwise, which provides an earlier investment signal, while the height of the price spikes is limited. Average prices should remain the same in the long run: because the reserve reduces the frequency of real shortages, the infrequent but high price spikes of an energy-only market are replaced by more frequent, but lower price spikes. This stabilizes prices, to a degree. The fundamental difference with a strategic reserve is that the system operator does not dispatch the additionally contracted reserves, but lets market parties decide whether to offer the reserves to him or to the spot market. This makes for a very clear dispatch rule for the reserve capacity: when the spot market exceeds the system operator’s willingness to pay for reserve capacity, the generating companies will start offering it to the market. The incentives for generating companies are quite similar to those provided by a strategic reserve: they earn from selling reserve capacity to the system operator and the withdrawal of a certain amount of capacity causes prices to rise sooner than in an energy-only market. Advantages of operating reserves pricing are that it does not disturb the merit order of the dispatch of generation facilities and that the system operator does not become a major seller of electricity, like a strategic reserve; that it stabilizes prices (to a degree) and that it is easy to implement. However, the same obstacles will need to be surmounted as in the case of a strategic reserve in order to calculate the correct combination of the volume of the reserve and the optimal willingness to pay for reserves. The latter corresponds to the dispatch price of a strategic reserve and determines the investment incentive for generating companies. Second, while operating reserves pricing should dampen investment cycles, it may not eliminate them. It is true that prices start to rise sooner than in an energy-only market, giving an earlier investment signal, but it is still a question how soon generating companies will respond, and whether enough time is left then before a physical shortage develops. Another important objection is (again) that operating reserves pricing does not appear effective in an open, decentralized market. The higher prices during shoulder periods may not even stimulate investment within the system, but lead to more imports, while the limiting effect of the reserve upon peak prices may prompt exports when neighboring systems are short of capacity.

We now arrive at a different type of capacity mechanism, one that directly regulates the volume of generating capacity rather than by influencing the electricity price or the cost of generating capacity. The PJM electricity market in the east of the USA, one of the largest competitive electricity markets in the world, uses a system of capacity requirements to maintain generation adequacy (PJM Interconnection LLC, 2003). The principle of this capacity mechanism is that the system operator requires loadserving entities to purchase enough capacity credits from the generating companies to cover their own peak demand, so that the system as a whole is ensured of enough generating capacity to meet system peak demand plus a reserve margin.5 The desired reserve margin between generating capacity and peak demand is administratively determined. Based upon the expected total coincident peak demand of the loads served by each load-serving entity (retail company or large consumer), the system operator calculates how much generating capacity each load-serving entity must purchase (PJM Interconnection LLC, 2003). As generating companies finance a significant part of their fixed costs with the sales of capacity credits, they no longer need the revenues from price spikes. Therefore capacity requirements are accompanied by a price cap. Reserve capacity may take the form of available generating capacity or interruptible contracts. Generating companies may sell capacity credits up to the volume of generating capacity that they have reliably available. To this end the regulator rates the availability of their generators. Capacity credits can be traded in a secondary market. Load-serving entities include the cost of purchasing capacity credits in the price that they charge final consumers for electricity. However, the cost of the capacity credits is offset by a reduction in price spikes, brought about by the reserve margin and enforced with a $1000/MWh price cap. The requirement for load-serving entities to contract generating capacity in excess of the projected peak causes the capacity market to become constrained before the energy market does. Consequently, the investment incentive develops before there is a shortage of electricity. If the capacity margin is large enough, this leaves enough time to bring new generating capacity on line. For generating companies, the incentives are somewhat similar to those provided by capacity payments, as they receive money per unit of generating capacity that they make available. There are two significant differences with regular capacity payments, however. First, the price of capacity is the result of a market process. Second, the total demand for capacity is determined administratively. So while traditional capacity payments fix the price (subsidy) for capacity and leave the volume unregulated, a capacity requirement fixes the total volume of capacity and leaves the price to the market. This resolves the price-quantity issue that was mentioned in Section 4.1.

5

‘Load-serving entity’ is PJM’s term for parties that are licensed to provide electricity to PJM consumers. A load-serving entity may be thought of as a retail company or a large power consumer.

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Generating companies have little volume risk when investing; their main risk is that a slight overcapacity, in excess of the total capacity requirement, causes the price of capacity to drop steeply. The main advantage of capacity requirements is that they provide a robust way to maintain a certain capacity margin. The investment incentive does not depend upon the generating companies’ forecasts of future electricity prices, but upon the regulator’s projections of peak demand and the resulting capacity requirements. Because it is easier to project peak demand than prices, this system is less affected by information deficiencies and other sources of investment risk than an energy-only market. Prices can be expected to be much more stable than in an energy-only market, not only because of the price cap, but also because investment cycles are suppressed. Capacity markets are complicated and need to be designed carefully. PJM has experienced several design problems. One is that a firm reserve requirement creates a perfectly inelastic demand for capacity, which provides a venue for the exercise of market power. Stoft (2002), among others, suggested making the penalty to load-serving entities who are short of their capacity obligations price-elastic: it should increase with the magnitude by which a load-serving entity does not meet its capacity requirement. This would reduce both the volatility of the capacity credit prices and the incentive for withholding generating capacity. FERC (2006) just approved changes to this end, among other adjustments such as requiring the capacity to be contracted four years in advance and adding locational requirements. Another practical problem in the initial PJM design was that generators could ‘delist’ their capacity on short notice (Hobbs et al., 2001a). Thus they could earn revenues in the capacity market when electricity demand was low, and sell at high prices in the (neighboring) electricity market when that was more profitable. The solution was to increase the minimum duration for which capacity credits may be sold, so generators need to decide for a whole season at once whether to offer capacity credits, and to require a longer notice for de-listing reserve capacity. However, the strength of these rules depends upon the penalty for non-compliance. Restricting exports requires a mandatory pool, in which all physical trade goes through the pool and the market operator also is the system operator. Only then does the system operator have a means for verifying that commitments to sell to the pool are met. By providing the load-serving entities in the pool, who have the capacity credits, with first priority for purchasing electricity, the system operator can secure their supply of electricity. In a decentralized market, on the other hand, the system operator and the market operator (who are two separate agents) have no means for controlling whether consumers resell their electricity outside the system. Thus in decentralized markets, requirements to sell to the local market are meaningless. This would complicate the introduction of a capacity requirement in an open, decentralized market. Another issue is that capacity requirements can be gamed by providing reserve capacity that is not actually operational: it rewards ‘iron in the ground’. In PJM the penalty to

27

generators that have sold capacity credits but that are not available apparently is too low, given the probability of being caught, so the expected revenues from selling capacity credits exceed the expected amount of penalties to be paid (Hobbs et al., 2001b). It would be better not to reward generating companies for providing capacity, but for the amount of capacity that they actually have available when needed. Reliability contracts, the next capacity mechanism, are designed for this purpose. We may conclude that capacity requirements perform reasonably well on most of the criteria that were presented in Section 3, as solutions have been developed for most of the problems that were encountered in PJM. The main issue would be implementation in decentralized markets (without a mandatory pool) that have significant exchanges with neighboring markets that do not have a similar capacity mechanism in place. As mentioned above, PJM experienced problems with generators who sold capacity credits but exported their power when prices in neighboring systems were higher, so they did not actually contribute to the reliability of the PJM system. In a mandatory pool like PJM, the pool operator has the ability to ‘recall’ exports; this possibility does not exist in decentralized markets such as in Western Europe. This issue is addressed in Section 4.6. 4.5. Reliability contracts Reliability contracts are designed as an improvement upon capacity requirements, with the purpose of providing generators with better incentives for making their resources available during periods of scarce supply.6 An independent agentdlet us assume the system operatordpurchases call options from generators on behalf of consumers. The call options provide the agent with the right to the difference between the electricity spot price Pm and the option strike price Ps. This price difference is then returned to consumers, so the net amount they spend, and generating companies receive, during price spikes is limited by the option strike price. The strike price functions effectively as a price cap. The volume of the contracts and the strike price are determined by the system operator and/or the regulator. The volume of reliability contracts is equal to the forecast coincident peak load plus a reserve margin, similar to a system with capacity requirements. The strike price should be above the highest marginal cost of operation of all the generators, to make sure that it does not discourage any generator from producing. The system operator organizes an auction in which he purchases the contracts from the generating companies. Thus the option premium is determined by the generating companies in a competitive process and will reflect the generating companies’ expected loss of revenues during times that the market price exceeds the option strike price (Pm > Ps). The system operator calls the options whenever the market price exceeds the option strike price. When the options are called, generating companies who have sold options pay the 6

The description is based upon Va´zquez et al. (2002).

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system operator Pm  Ps times the volume (in MW) for which they have sold options. An operational generator will receive Pm from selling electricity in the market, so the net price he receives will be Ps, namely Pm minus his payment (Pm  Ps). The generating company is fully hedged against high market prices as long as the generator that underlies the option contract is operational. A generator who has sold option contracts but happens to be unavailable when the options are called, still is required to pay (Pm  Ps), but does not have any revenues to compensate these payments. Consequently, the payments cause a net loss that increases with the market price, so the generator’s incentive for producing increases with scarcity. Therefore generating companies have a strong incentive for making their capacity available when the options are called, which is when electricity is scarce. This is an important advantage of reliability contracts. A second advantage is that generating companies have an incentive for selling a volume of call options equal to their expected output: selling less would lower their revenues, while selling more would expose them to price risk. Thus the generating companies are stimulated to reveal the reliably available volume of generating capacity. For consumers, the effect is that the system operator has ‘purchased’ a price cap equal to Ps. As this limits the average revenues of generating companies, the latter will demand a price for selling the option contracts that corresponds to the expected loss of price spike revenues, which is the sum of (Pm Ps) over all hours that Pm > Ps. As the option price is determined in a competitive auction, it should reflect generators’ expected forgone price spike revenues. If the system functions well, there should be no net cost to consumers, as the price paid for the reliability contracts should be offset by the reduction of price spikes, similar to the case of capacity requirements. Thus the net effect for consumers is stabilization of electricity prices as well as better reliability. If the reliability contracts induce a higher volume of generating capacity than is socially optimal, the costs of the extra generating capacity would still at least partly be offset by the benefit of increased reliability and reduced generator market power. Reliability contracts are the first capacity mechanism to be discussed here in which generating companies actually sell a product that directly improves security of supply. As they are a kind of call option, reliability contracts provide consumers with a financial hedge against high prices. Thus consumers receive a well-defined benefit in exchange for the payments made to the generating companies. Through their structure, reliability contracts also provide generating companies with an incentive for providing an administratively determined volume of generating capacity and to maximize its availability when the demand is there. Reliability contracts should have the same stabilizing effect upon electricity prices as capacity requirements. They combine the advantage of capacity requirements of providing a clear, capacity-based investment signal with better operational incentives and therefore appear to be an attractive solution. There are three issues, however. The first is that the auctions in which the system operator purchases the reliability

contracts must be designed carefully to minimize generator market power. Va´zquez et al. (2004) present some suggestions. Key is to minimize the barriers to new market entrants. To this end, auctions should be held a number of years in advance, so parties without generating capacity may first sell reliability contracts in the auction and then construct the necessary generating capacity. The risk for newcomers is also lowered by increasing the duration of the reliability contracts. However, this reduces the auction liquidity, so there is a trade-off to be made. The second issue is the compatibility of this proposal with decentralized markets. The original proposal by Va´zquez et al. (2002) was designed for an integrated market with a mandatory pool, in which the system operator has greater control over the market transactions than in a decentralized market. An important question is how to accommodate bilateral contracts. Generating companies who have sold their output through long-term bilateral contracts would lose when the options are called, even if their output equals the volume of option contracts that they have sold, because they do not receive the high spot prices but only the bilateral contract price. Va´zquez et al. (2004) propose to let generating companies who hold bilateral contracts sell reliability contracts for their full output and also to let them make option payments for the same volume when the options are called, but to return these payments through parallel contracts to the extent that the generating companies can show that they have sold their output through longterm bilateral contracts. When the options are not called, the generating companies meet their bilateral contract obligations and sell any unused capacity to the spot market. When the options are called, the generating companies need to produce as much as they committed in their reliability contracts. Then they receive the strike price for the electricity that they sell to the spot market and receive the contract price for the electricity sold under bilateral contracts. If their output falls short of what the generating companies committed in their reliability contracts, they pay the market price minus the strike price for the capacity that was committed but is unavailable. The third issue in decentralized markets is compatibility with trade with neighboring markets. This version of reliability contracts should also be robust in this respect. As the options hedge consumers for their full demand, the load-serving entities can bid any price, if necessary, to obtain enough electricity for their consumers, because they are fully hedged against price spikes. This should allow them to out-bid competitors from neighboring energy-only markets, who should not be willing to bid more than their value of lost load. Therefore the consumers in the market with reliability contracts should always be able to obtain the volume of electricity that was committed to them in the reliability contracts that they purchased. While this proposal works on paper, it may be vulnerable to gaming. First, the measures to mitigate market power in the auctions must be balanced with the need for liquidity. Second, the large financial flows that circulate between the generating companies, the system operator and consumers would provide a natural focus point for manipulation. Versions of reliability contracts have been implemented in Ireland (EC 2003) and Brazil (Bezerra et al., 2006), while Spain is working on

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a modified form, in which more parameters are determined administratively because the Spanish market is too concentrated to fully rely upon competition (Batlle et al., 2006). 4.6. Bilateral reliability contracts An alternative, described by De Vries et al. (2004), would be a bilateral variant of reliability contracts, in which the loadserving entities purchase the option contracts.7 This is more similar to PJM’s system of capacity requirements, with the exception that the load-serving entities purchase options instead of capacity credits. By requiring the load-serving entities to purchase options for power in excess of their demand, it is ensured that they will always be able to purchase enough electricity to meet their demand at a predetermined maximum price. The financial flows would be straightforward: the load-serving entities pay the generating companies the option premium, and the generating companies pay the load-serving entities the market price minus the strike price (Pm  Ps) when the options are called. There is no need for financial involvement of the system operator or for reimbursements to generating companies with bilateral contracts. Rather than reimbursing the end consumers for high prices, bilateral reliability contracts limit the purchasing costs of load-serving entities and hence prevent the need for high retail prices. Bilateral reliability contracts could be adjusted to reflect the preferences of the contract parties. For instance, if two parties agree upon an option contract with a low strike price, this contract would converge with a ‘regular’ bilateral contract, in which electricity is sold for a specific price. Therefore there is no need to make this system compatible with bilateral contracts. The regulator would need to apply some limits, however. The strike price would need to be limited to a maximum; if it were allowed to be as high as the average value of lost load, the option premium would be zero and the option contract would be meaningless, rendering the option requirement void as well. Then the free-riding opportunities that cause underdevelopment of long-term contracts in an energy-only market would remain (De Vries et al., 2004). Similarly, the minimum duration of the contracts would need to be regulated in order to provide a sufficiently stable investment signal and to prevent the option requirement from becoming meaningless. A system of bilateral reliability contracts eliminates the need for auctions. A bilateral market should be more robust against the exercise of market power than auctions for two reasons. First, because the load-serving entities compete with each other in the market for reliability contracts they have a stronger incentive to minimize costs than the system operator has in the centralized variant, as the system operator can pass the cost of the reliability contracts on to the consumers. Second, the loadserving entities have more options for mitigating market power, such as reducing peak load through demand-side management programs and installing their own generating capacity. 7 The seminal ideas for this variant are provided by Oren (2000) and Va´zquez et al. (2004).

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The main question about bilateral reliability contracts is whether they work in a market in which generating companies are vertically integrated with retail companies, as is common in Europe. Option contracts between the generation and retail components of a company are meaningless. It may be necessary to rate the availability of the company’s generating assets, like PJM does, and to subtract the in-company volume of available generating capacity from the company’s obligation to purchase reliability contracts. This, however, could diminish some of the fundamental advantages of reliability contracts, namely stimulating generating companies to make a best estimate of the availability of their generators when they sell their option contracts and maximizing their output during shortages. This disadvantage needs to be weighed against the advantage of avoiding a central auction of options, as in the reliability contracts proposal, and the complications of implementing reliability contracts in a decentralized system. 4.7. Capacity subscriptions A fundamentally different capacity mechanism, which promises to be the most market-oriented of all, is the system of capacity subscriptions (Doorman, 2000). This capacity mechanism directly involves consumers by requiring them to purchase electronic fuses which, when activated, limit their electricity consumption to a predetermined capacity. Each consumer chooses the level of capacity that he wishes to have permanently available to him and pays for it per unit of capacity. As a result, a capacity market develops between generating companies and consumers. In this market, consumers choose between purchasing a high volume of firm capacity and risking that their consumption is limited during shortages. The risk of peak prices is removed, because during shortages capacity is allocated according to capacity subscriptions, not through the price mechanism. As a result, electricity prices should be extremely stable as they should not be expected to exceed the marginal cost of generation. In addition, this mechanism has three advantages: it provides consumers with an incentive to limit their peak consumption, it produces a clear indication of the demand for generating capacity, and it provides a steady revenue stream which helps to finance generating capacity. The original proposal does not appear robust against intersystem trade in a decentralized market. Generating companies who have sold capacity subscriptions to consumers within the system could still sell their output outside the system. A solution could be a financial version, which again uses option contracts (De Vries, 2004). The difference with reliability contracts is that now the option contracts are purchased directly by consumers, rather than by the system operator or by loadserving entities. To ensure that peak consumption is indeed within the contract limits, real-time meters would be required. Both variants have significant implementation requirements, which is why we will not discuss them further. However, as real time meters are becoming more affordable, this capacity mechanism deserves fresh consideration. An important caveat is that it is an open question how consumers will respond to

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this scheme. It is unclear whether they have the necessary information, skills and interest to make informed decisions in the capacity market. 4.8. Conclusions of the overview of capacity mechanisms As was mentioned in the introduction to this section, capacity mechanisms that provide a capacity signal are preferable over those that provide a price-related investment signal. Probably the most effective capacity mechanism that has been tried in practice is PJM’s system of capacity requirements. Unfortunately, it appears that this system cannot be implemented in its current form in most European markets. There would be a risk of ‘leakage’ in case of unilateral implementation: if one country implements a capacity requirement, its reserve capacity could be sold outside the country in case of a regional shortage, so that the net contribution to the reliability within the country would be diluted. Capacity requirements would work, however, if implemented in a large, contiguous region with relatively limited outside trade, such as the UCTE area. Reliability contracts could be designed to be robust in this respect, both the central and a bilateral variants. Reliability contracts are a relatively new capacity mechanism, however, which means that there may be a higher risk of policy failure. With the advent of real-time meters, a variant of capacity subscriptions may be the most effective and economically efficient solution, but it is unclear how consumers would respond to such a scheme. 5. Policy framework The previous sections provided a brief overview of the advantages and disadvantages of the main types of capacity mechanism. There is no silver bullet: none of the solutions is without flaws. Especially for most European markets, which are decentralized electricity systems (without a mandatory pool) and have significant exchanges with neighboring systems, the choices are limited. This section discusses the policy choices that are to be made when dealing with the issue of generation adequacy, with a focus upon European electricity systems. 5.1. Implementation as a precaution? The first question to be answered is whether a capacity mechanism should be implemented now, or whether we should wait and see how the market develops, considering the lack of empirical evidence of market failure? Policy choice 1: Should a capacity mechanism be implemented as a preventive measure, which is easier, but for which the need has not been proven, or should it only be implemented when the need is clear, which means that reliability may be jeopardized for some time and the transition phase may be more difficult? Waiting entails a significant risk, because it is not possible to monitor the market and forecast generation adequacy with

sufficient certainty, far enough into the future, to allow time for policy intervention when it becomes apparent that a shortage of generating capacity looms. Not only does the development and implementation of a capacity mechanism take time; generating companies will also need time to evaluate the capacity mechanism’s implications in order to adjust investment strategies and, last but not least, it will take time to construct additional generating capacity in response to the new capacity mechanism. If, in the mean time, the volume of generating capacity drops below the level that the capacity mechanism is designed to obtain, a difficult transition period will follow. During this period the reliability of service will be lower than desired, while the inability of the market to immediately provide the desired volume of generating capacity may cause high capacity prices in a capacity market or in a system with capacity subscriptions. Implementation of a capacity mechanism during a period of excess capacity is much easier, as it does not require an immediate reaction from the market. The market could continue to reduce the capacity margin until the limits of the capacity mechanism would be reached, after which it would stabilize. The smoother transition and the lower risk to the reliability of service are arguments in favor of a ‘preventive’ strategy.

5.2. Unilateral or regional implementation? Strongly interconnected electricity systems face the question whether to implement a capacity mechanism themselves or whether to attempt to develop a joint solution with their neighbors. This is particularly an issue for EU member states. Subsidiarity is a leading principle in the EU, but a regionally coordinated solution is simpler, more economically efficient and allows for a wider choice of capacity mechanisms. A system of capacity requirements, for instance, can be implemented without much difficulty in a decentralized market if there are no significant imports and exports. If there are, one of the variants of reliability contracts needs to be used. Importing countries may be most worried about declining reserve margins, but a regional shortage would also affect exporting countries, as they would be ‘importing’ price spikes from neighboring markets. Thus the issue really is of general concern in a region with interconnected markets. However, regional implementation of a capacity mechanism may take too long to avoid a first investment cycle, especially in a network with as many political jurisdictions as the UCTE. The alternative is for individual countries to implement their own capacity mechanism. However, this is more complicated, as border issues need to be dealt with, because it will most likely distort international trade in electricity, and because it limits the options. A dilemma is the consequence. Policy choice 2: Should countries implement a capacity mechanism unilaterally, despite all its disadvantages, or try to develop a collective solution and hope that it will be implemented in time?

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5.3. Self-reliance? If the choice for unilateral implementation is made in a market with strong interconnections, another question presents itself. Should physical self-reliance be the goal? Alternatively, to which degree can imports be relied upon in the long term? At issue are not only the physical availability of imports, but also the price at which they are available. Capacity mechanisms tend to reduce the price volatility of electricity markets; some provide an upper limit to the payments for energy. Imports from neighboring energy-only markets could undo this effect, because arbitrage would cause prices to be equal in the connected markets (unless the interconnectors were congested). For consumers, the consequence would be that they would pay the cost of the capacity mechanism without enjoying the benefit of lower prices. This would undermine some of the main advantages of having a capacity mechanism. For these reasons the choice may be made to become selfreliant, if neighboring systems do not implement a similar capacity mechanism. The cost of self reliance may be high, however, for electricity systems with a large share of imports. They may compromise by requiring a lower reserve margin in their capacity mechanism than would be considered optimal in an isolated system. While this reduces their security of supply to the extent that the imports are not dependable, it also reduces the cost of supplementing these imports with presumably inactive back-up generation. Another solution could take the form of firm import contracts, combined with corresponding contracts for network capacity in the case of congestion. In the latter case, a complication is presented by the fact that congested network capacity is typically not auctioned for longer periods than one year, which would be too short for purposes of security of supply. Policy choice 3: If a capacity mechanism is implemented in an open market, should self-reliance be the goal? If not, to what degree should imports be depended upon? 5.4. Innovativeness The analysis in Section 4 showed that the innovative variants of reliability contracts can in theory work in open, decentralized markets, but the lack of experience casts some uncertainty upon their practical merits. Theoretically, they should provide better incentives to generating companies and be robust with respect to inter-system trade. However, the vulnerability to gaming, for instance, of these untried solutions is unknown. This raises another policy dilemma: Policy choice 4: Should a capacity mechanism be chosen that has been tried in practice, but has known flaws, or should the choice be made for a more innovative system with better theoretical incentives, but perhaps unknown flaws? In the case of unilateral implementation in a decentralized market with strong interconnections, the only options that

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even work on paper are the innovative variants of reliability contracts. The alternatives are doing nothing (and perhaps to try to achieve a regional solution) or to implement a capacity mechanism of which the effectiveness is uncertain. In a centralized system (with a mandatory pool), PJM’s system of capacity requirements may be implemented, also if there are strong interconnections. 5.5. Timeliness In selecting a capacity mechanism, the specific circumstances of the system within which it is to be implemented should be taken into account. If a capacity shortage is already looming, it may be necessary to implement a capacity mechanism that can be implemented quickly, as a transition measure, even if it does not meet all the criteria. Capacity payments, a strategic reserve and operating reserves pricing are relatively easy to implement, which makes them attractive as short-term solutions. Unfortunately, their effectiveness is limited and they entail a risk of distorting investment incentives. Whether to implement a short-term solution is a judgment call: if it is estimated that enough time remains to develop a more elaborate, but also more effective and efficient capacity mechanism, this will be preferable. Policy choice 5: Should a price-based capacity mechanism be chosen, which can be implemented quickly, or a quantity-based capacity mechanism, which requires more development and implementation time, but also is more effective and efficient? If the decommissioning of old units threatens the capacity margin, the system operator may choose to purchase them as a strategic reserve (providing he has the authority to do so). Creating a strategic reserve this way was Sweden’s response to concerns about generation adequacy in recent years. An alternative that can be implemented just as easily is operating reserves pricing. Expanding the operating reserves when the reserve margin is below the target level would immediately create an investment signal. The disadvantages of these methods are that their effectiveness in stimulating investment is uncertain (so an investment cycle may yet develop), that they mitigate, but do not eliminate the problem of capacity withholding in the electricity market, and that they are not robust against regional shortages. Therefore they should only be considered as temporary solutions. If more time is available (in the order of five to ten years before a shortage is projected), a version of reliability contracts appears more effective and efficient. 5.6. Overview of the policy choices The policy choices are summarized in Fig. 2. The diagram shows the consecutive choices that present themselves and to which capacity mechanisms they lead. The first choice is whether a capacity mechanism will be implemented immediately, as a precaution, or only when it becomes clear that the market is not providing sufficient generating capacity. Waiting

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32 implement capacity mechanism as a precaution?

no

wait and see (monitor)

yes regional implementation possible? no solitary implementation

yes

strong interconnections?

yes

no enough time for developing longterm solution?

yes

no

• (strategic reserve) • reliability contracts • bilateral reliability contracts • financial capacity subscriptions • strategic reserve • operating reserves pricing (as a temporary solution…) …while developing a long-term solution • capacity requirements • reliability contracts • bilateral reliability contracts • capacity subscriptions (physical or financial)

Fig. 2. Decision framework for implementation of a capacity mechanism in a decentralized market.

is a risky policy, because failure of the market to provide sufficient generation capacity cannot be predicted far enough in advance to implement a capacity mechanism and construct new capacity. The next issue is whether regional implementation is feasible, as this is preferable over implementation in individual systems within a larger interconnected network. If regional implementation of a capacity mechanism does not appear possible in time to avoid a shortage, individual systems may need to take action. If they are weakly interconnected, the absence of regional measures does not matter much, as all options are still open. Unilateral implementation of a capacity mechanism in a strongly interconnected system is a difficult issue. Of the capacity mechanisms presented in Section 4, only capacity requirements, reliability contracts and a strategic reserve are robust against a regional shortage. This means that in a decentralized market the choice is between one of the innovative versions of reliability contracts and a strategic reserve. The UCTE as a whole is so large, relative to the exchanges with its neighbors, that it can be considered as an isolated system for the purposes of security of supply. Examples of other relatively isolated electricity markets are those in the UK, Ireland and the Iberian Peninsula. These markets are in the comfortable position of having all options available, also because they are not under pressure to implement a temporary solution as a transition measure. It is precisely those countries, on the periphery of the continental network, who have already experimented with capacity mechanisms.

Development of a capacity mechanism at the level of the UCTE, or even for part of it, may take too long for some member systems. The Netherlands and Italy are the largest importing countries in the EU (UCTE, 2005b), which may given them cause for concern with respect to future reliability. If these countries would decide to implement a capacity mechanism independently, they would need to choose one that is robust with respect to imports and exports. In a decentralized market, the best option appears to be a variant of reliability contracts. In Nordel, the shortages in Sweden and Norway have prompted implementation of a strategic reserve and a form of operating reserves pricing, respectively, as short-term solutions while a longer-term solution is being developed. 5.7. Implementation issues 5.7.1. Adaptation to local conditions If the choice is made for capacity requirements, the ample experience in the PJM system provides the opportunity for empirical study of this capacity mechanism. Much has already been written about PJM’s ICAPs; however, when considering implementation of capacity requirements in another system, the potential impacts of the differences between the two systems should be assessed. For instance, large imports have not been an issue in PJM. Unilateral implementation of an effective and efficient capacity mechanism in one of Europe’s decentralized markets requires innovation. None of the available systems are fully satisfactory, with the possible exception of capacity subscriptions in a closed system. As there are some questions about the feasibility of the latter, the possibilities of developing reliability contracts should be further explored. New systems must be thoroughly tested with respect to their ability to stabilize the generation volume in the presence of insufficient information regarding future supply and demand conditions and in the presence of risk-averse behavior by both producers and consumers. In addition, they should be robust against the exercise of market power among generating companies, both in the short and the long term. 5.7.2. Strategic behavior The art of implementing a capacity mechanism is to guard against new possibilities for strategic behavior. In general, the combination of a regulated volume of generating capacity and the fact that generating capacity cannot be expanded on short notice creates an opportunity for capacity withholding somewhere. In the case of reliability contracts, the generating companies may manipulate the contract auction; in the case of capacity subscriptions, the generating companies may be able to artificially raise the prices of the subscriptions. The vulnerability of these capacity mechanisms must be tested, in a model and/or in practical tests, before they can be implemented with any confidence. Other opportunities for manipulation may develop through exchanges with neighboring systems with different market models. Implementation of a capacity mechanism should lead to a larger reserve margin and lower prices at times when the

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Table 1 Responsibilities with respect to generation adequacy

Capacity payments Strategic reserve

Operating reserves

Capacity requirements

Reliability contract

Bilateral reliability contracts

Capacity subscriptions

Government or system operator

Generating companies

Determine capacity payment Estimate the optimal volume of generating capacity Determine the volume of reserve capacity and the reserve dispatch price Purchase and operate the reserve capacity Monitoring and enforcement Estimate the optimal volume of generating capacity Determine the volume of reserve capacity and the maximum reserve price Purchase reserves Monitoring and enforcement Estimate the optimal volume of generating capacity Monitoring and enforcement Estimate the optimal volume of generating capacity Purchase reliability contracts Monitoring and enforcement Estimate the optimal volume of generating capacity Monitoring and enforcement Monitoring and enforcement

Operate all generating capacity Determine the reserve capacity price

Consumers

Operate non-reserve generating capacity

Determine the reserve capacity price Operate all generating capacity

Determine the capacity price

Load-serving entities purchase capacity credits

Operate all generating capacity Determine the capacity price Operate all generating capacity Determine the capacity price Operate all generating capacity Determine price of capacity subscriptions

Purchase reliability contracts

Estimate the optimal volume of generating capacity

Operate all generating capacity

system otherwise would have been under stress. Care must be given that the consumers who pay for reliability also benefit from the capacity mechanism. In this respect direct contracts between consumers and generating companies, such as in a system of bilateral reliability contracts or capacity subscriptions, appear more robust than the centralized version of reliability contracts. 5.7.3. Assignment of responsibilities It is the task of the system operator to maintain the operational reliability of the electricity system. To this end, system operators contract system reserves (also called regulating power) with which they can correct imbalances between supply and demand in real time. This obligation places system operators in energy-only markets in an awkward position with respect to the long term, as they do not have any means to influence the volume of available generating capacity. A comparison of European countries shows that the responsibilities for generation adequacy generally are restricted to monitoring by the system operator or by a government agency (UCTE, 2005a). In some cases, there is a planning requirement, however without the planner having a means for implementing the plans with respect to generation investment. The actual provision of generation resources is generally left to the market. If a choice is made to implement a capacity mechanism, responsibilities need to be assigned for:

Except for capacity subscriptions, all capacity mechanisms have in common that the desired capacity margin is the same for all consumers. The optimal volume of generation adequacy, which determines system reliability, could in theory be determined through a benefit-cost analysis. The marginal cost of providing a generation capacity should equal the marginal social benefits. However, these calculations are difficult to make, in particular because the social cost of service interruptions is difficult to determine. As a result, the level of reliability becomes a political choice, in which the cost of electricity is weighed against the perceived acceptability of occasional service interruptions. The second issue is who makes the operational decisions. This depends upon the capacity mechanism that has been chosen. In a centralized system, such as operating reserves pricing or a strategic reserve, the system operator decides when to dispatch the reserve units. Capacity requirements and reliability contracts leave this decision to the market: they place the responsibility to provide a certain level of generating resources with the market. The same is true for capacity subscriptions. Monitoring, finally, is a function that should be performed by an independent agent, so a government body (such as the regulator) and the system operator are likely candidates. Table 1 presents an overview of the distribution of responsibilities under the different capacity mechanisms. 6. Conclusions

 choosing the desired level of reliability of electricity service (except in the case of capacity subscriptions);  operational decisions concerning the capacity mechanism;  monitoring and enforcing the system.

Competitive energy-only markets appear prone to investment cycles. Resulting episodes of scarcity may provide generating companies with substantial market power: by

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withholding generating capacity, they may be able to raise electricity prices substantially. These factors, combined with the asymmetry of welfare losses if the volume of generating capacity is less than optimal, are reasons for implementing a capacity mechanism. This paper’s contribution consists of two parts: the evaluation of capacity mechanisms and the development of a policy framework for selecting the most suitable capacity mechanism. The main factors that influence the selection of a capacity mechanism are the amount of time that is available, whether the market in which the capacity mechanism is to be implemented has a mandatory pool and whether it has strong interconnections. Of the reviewed capacity mechanisms, capacity requirements (PJM’s system of ICAP) and reliability contracts appear to best meet the policy goals of stabilizing the volume of generating capacity in an efficient way. Capacity requirements have as an advantage that practical experience is available, whereas reliability contracts promise to provide more efficient incentives to generating companies. Implementation of these capacity mechanisms in European markets is not straightforward, however. Both capacity requirements and reliability contracts were designed for markets with a mandatory pool, in which exports can be limited more easily during shortages. In decentralized markets, which are more common in Europe, it is much more difficult to limit exports, as electricity can always be resold outside the system. The TSO only sees the transmission schedules, not the contracts associated with them, and can therefore not verify which production was committed to sales within the system. However, it only makes sense to support investment in generating capacity if the capacity is available to those who have paid for it when they need it. Therefore the capacity mechanisms need to be adjusted to decentralized systems. The best solution appears a form of mandatory call options between producers and a party that acts on behalf of consumers, or a bilateral version that would resemble capacity requirements, except that load-serving entities would purchase options rather than capacity credits. Measures to make a capacity mechanism efficient in the presence of international trade inevitably will also distort this trade. Therefore joint implementation by a group of strongly interconnected systems is strongly preferred. If implemented in a large region, for instance in the UCTE, the impact of trade with parties outside this region would become small. A second, important advantage is that this would greatly simplify the design of a capacity mechanism and make more options, such as regular capacity requirements, available. Therefore an international initiative is called for, for instance by the UCTE or the EU. In the absence of a regional capacity mechanism, individual countries are faced with a dilemma. Doing nothing entails a risk that the investment incentive comes to late to avoid a first investment cycle, whereas unilateral implementation of a capacity mechanism is complicated and carries a risk of regulatory failure. Unilateral implementation also has a risk of being superseded by European policy later on.

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