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Financial derivatives are important hedging tool for asset’s manager. Electricity is by its very nature the most volatile commodity, which creates big incentive to share the risk among the market participants through financial contracts. But, even if volume of derivatives contracts traded on Power Exchanges has been growing since the beginning of the restructuring of the sector, electricity markets continue to be considerably less liquid than other commodities. This paper tries to quantify the effect of this insufficient liquidity on power exchange, by introducing a pricing equilibrium model for power derivatives where agents can not hedge up to their desired level. Mathematically, the problem is a two stage stochastic Generalized Nash Equilibrium and its solution is not unique. Computing a large panel of solutions, we show how the risk premium and player’s profit are affected by the illiquidity.

Although there are mechanisms to control market power in the spot market, withholding investments can still increase profits and hence hamper adequate capacity expansion. We examine the effect on investment of one suggested approach to reducing market power, contracting longer term. We construct a stylized model of an energy only market where two firms, each specializing in one technology, invest in a first stage, contract part of their production in the second stage and sell the rest in the spot market in the third stage. We compare this model to one of an energy only market having two stages, investment and a spot market. We find cases where the contracts change neither capacity nor prices, where the foreclosing effect of one player blocking the other from contracts markets increases investments and reduces prices, and where the opportunity to foreclose the market can incentivize one firm to lower its investment and increase its pricing power to the detriment of consumers. The model relies on the simplest possible assumptions of imperfect competition (subgame perfect equilibria with Cournot agents). We illustrate the different outcomes in a numerical example with two load steps (peak and off-peak) where we change one parameter, the height of the off-peak time segment. We find that varying this parameter leads to outcomes with increased and decreased capacity as well as no change in capacity. Since there is no general characterization of the consequences of contracts in this simple example, regulators or competition authorities cannot rely on contracts to induce sufficient capacity expansion. One other market mechanism that has been proposed to induce investment, a capacity auction with predetermined capacity requirements is a potential alternative to limit market power that deserves further exploration to determine the extent to which it can provide the adequate incentive to invest in the presence of market power.

Financial derivatives are important hedging tool for asset’s manager. Electricity is by its very nature the most volatile commodity, which creates big incentive to share the risk among the market participants through financial contracts. But, even if volume of derivatives contracts traded on Power Exchanges has been growing since the beginning of the restructuring of the sector, electricity markets continue to be considerably less liquid than other commodities. This paper tries to quantify the effect of this insufficient liquidity on power exchange, by introducing a pricing equilibrium model for power derivatives where agents can not hedge up to their desired level. Mathematically, the problem is a two stage stochastic Generalized Nash Equilibrium and its solution is not unique. Computing a large panel of solutions, we show how the risk premium and player’s profit are affected by the illiquidity.

The persistent uncertainty about mid-century CO2 emissions targets is likely to affect not only the technological choices that energy-producing firms will make in the future but also their current invest-ment decisions. We illustrate this effect on CO2 price and global energy transition within a MERGE-type general-equilibrium model framework, by considering simple stochastic CO2 policy scenarios. In these scenarios, economic agents know that credible long-run CO2 emissions targets will be set in 2020, with two possible outcomes: either a ”hard cap” or a ”soft cap”. Each scenario is characterized by the relative probabilities of both possible caps. We derive consistent stochastic trajectories - with two branches after 2020 - for prices and quantities of energy commodities and CO2 emissions permits. The impact of uncertain long-run CO2 emissions targets on prices and technological trajectories is discussed. In addition, a simple marginal approach allows us to analyze the Hotelling rule with risk premia observed for certain scenarios.

Cross-border trade remains a contentious issue in the restructuring of the European electricity market. Difficulties stem from the lack of a common market design, the separation between energy and transmission markets and the insufficient coordination between Transmission System Operators (TSOs). This paper analyzes the cross-border trade problem through a set of models that represent different degrees of coordination both between the energy and transmission markets and among national TSOs.We first present the optimal organisation, not implemented in Europe, where energy and transmission are integrated according to the nodal price paradigm and Power Exchanges (PXs) and TSOs are integrated. This is our reference case. We then move to a more realistic representation of the European electricity market based on the so-called market-coupling design where energy and transmission are operated separately by PXs and TSOs. When considering different degrees of coordination of the national TSOs’ activities, we unexpectedly find that some arrangements are more efficient than the lack of coordination might suggest. Specifically we find that even without a formal coordination of the TSOs’ counter-trading operations, non discriminatory access to common counter-trading resources for all TSOs may lead to a partial implicit coordination of these TSOs. In other words, an internal market of counter-trading resources partially substitutes the lack of integration of the TSOs. While a full access to counter-trading resources is a weaker requirement than the horizontal integration of the TSO, it is still quite demanding. We show that quantitative limitations to the access of these resources decrease the efficiency of counter-trading. The paper supposes price taking agents and hence leaves aside the incentive to game the system induced by zonal systems.

The pricing of contingent claims in the wholesale power market is a controversial topic. Important challenges come from the non-storability of electricity and the number of parameters that impact the market. We propose an equilibrium model based on the fundamentals of power generation. In a perfect competitive market, spot electricity prices are determined by the marginal cost of producing the last unit of power. Electricity can be viewed as a derivative of demand, fuels prices and carbon emission price. We extend the Pirrong-Jermakayan model such as to incorporate the main factors driving the marginal cost and the non-linearities of electricity prices with respect to fuels prices. As in the Pirrong-Jermakayan framework, any contingent claims on power must satisfy a high dimensional PDE that embeds a market price of risk, as load is not a traded asset. Analyzing the specificity of the marginal cost in power market, we simplify the problem for evaluating power futures so that it becomes computationally tractable. We test our model on the German EEX for "German Month Futures" with maturity of June and September 2008.

The pricing of contingent claims in the wholesale power market is a controversial topic. Important challenges come from the non-storability of electricity and the number of parameters that impact the market. We propose an equilibrium model based on the fundamentals of power generation. In a perfect competitive market, spot electricity prices are determined by the marginal cost of producing the last unit of power. Electricity can be viewed as a derivative of demand, fuels prices and carbon emission price. We extend the Pirrong-Jermakayan model such as to incorporate the main factors driving the marginal cost and the non-linearities of electricity prices with respect to fuels prices. As in the Pirrong-Jermakayan framework, any contingent claims on power must satisfy a high dimensional PDE that embeds a market price of risk, as load is not a traded asset. Analyzing the specificity of the marginal cost in power market, we simplify the problem for evaluating power futures so that it becomes computationally tractable. We test our model on the German EEX for ”German Month Futures” with maturity of June and September 2008.

Real options present a wide topic in investment litterature nowadays. However, despite big advances in the single asset investment pricing, the theory is miser of informations about problems involving more than one asset. We show in this paper that using dynamic programming, one can find an analytic trigger for a three assets simple exchange problem. Although we get a forward investment rule, one can not find the precise option value ex ante but only an average value. The precise option value depends on the first exit time from the continuation region which is stochastic. This is a quite intuitive effect of the course of dimensionality of the problem. Valuating a single asset project gives a single condition for the optimal decision rule. The same holds for the simple exchange problem with two assets since the value of the project just depends on the price over cost ratio. In a three assets problem, as the project don’t depend anymore of a single state variable, one can’t region.

The progressive relocation of part of the Energy Intensive Industries (EIIs) out of Europe is one of the possible consequences of the combination of emission charges and higher electricity prices entailed by the EU-Emission Trading Scheme (EU-ETS). In order to mitigate this effect, EIIs have asked for special power contracts whereby they would be supplied from dedicated power capacities at average (capacity, fuel, transmission and emission allowance) costs. We model this situation on a prototype power system calibrated on four countries of Central Western Europe. In order to capture the main feature of EIIs' demand, we separate the consumer market in two segments: EIIs and the rest. EIIs buy electricity at average cost price while the rest pays marginal cost. We consider two different types of EIIs' contractual arrangements: a single region wide and zonal average cost prices. We also analyze the cases where generators only rely on existing capacities or can invest in new ones. We find that these average cost contracts can indeed partially mitigate the incentive to relocate activities but with quite diverse regional impacts depending on different national power policies. Models are formulated as a non-monotone complementarity problems with endogenous energy, transmission and allowance prices and are implemented in GAMS.

Competition, security of supply and sustainability are at the core of EU energy policy. The Commission argues that making the European gas market more competitive (completing the internal gas market) will be instrumental in the pursuit of these objectives. We examine the question through the eyes of existing models of the European gas market. Can model tell us anything on this problem? Do they confirm or infirm the analysis of the Commission appearing in fundamental documents such the Green Paper, the Sector Inquiry or the new legislation package? We argue that results of existing models contradict a fundamental finding (paragraph 77) of the Sector Inquiry. We further elaborate on the basis of the economic assumption underlying the models, that changing the assumptions implicitly contained in paragraph 77 cast doubts on a large part of the reasoning justifying the completion of the internal gas market. We also explain that models could help arriving at a better definition of the relevant market, which is so important in the reasoning of the Commission. Last we also find model results that question the effectiveness of ownership unbundling. As to security of supply, we explain that models can also contribute to assess the value of additional infrastructure in the context of security of supply, but this potential seems largely untapped. Last we note that sustainability has not yet penetrated models of gas markets. We conclude by suggesting other area of immediate concern, possibly of higher technical difficulty, that modellers could address in future research.

Former generation capacity expansion models were formulated as optimization problems. These included a reliability criterion and hence guaranteed security of supply. The situation is different in restructured markets where investments need to be incentivised by the margin resulting from electricity sales after accounting for fuel costs. The situation is further complicated by the payments and charges on the carbon market. We formulate an equilibrium model of the electricity sector with both investments and operations. Electricity prices are set at the fuel cost of the last operating unit when there is no curtailment, and at some regulated price cap when there is curtailment. There is a CO2 market and different policies for allocating allowances. Todays situation is quite risky for investors. Fuel prices are more volatile than ever; the total amount of CO2 allowances and the allocation method will only be known after investments has been decided. The equilibrium model is thus one under uncertainty. Agents can be risk neutral or risk averse. We model risk aversion through a CVaR of the net margin of the industry. The CVaR induces a risk neutral probability according to which investors value their plants. The model is formulated as a complementarity problem (including the CVaR valuation of investment). An illustration is provided on a small problem that captures the essence of today electricity world: a choice restricted to coal and gas, a peaky load curve because of wind penetration, uncertain fuel prices and an evolving carbon market (EU-ETS). We show that we might have problem of security of supply if we do not implement a capacity market.

Carbon leakage in this pape ris the phenomenon whereby Electricity Intensive Industries subject to harsh environmental standards move their activity or part of it to more environmentally lenient regions. Carbon leakage has been mentioned as a possible outcome of the EU Emission Trading Scheme. Different studies are underway to assess the reality of the phenomenon and to devise policies to mitigate its possible impact. One remedy, proposed by the Energy Intensive Industries is to combine free emission allowances with a pricing of electricity whereby energy émissions and transmission costs are bundled and sold on an average cost basis. The paper attempts to model this proposal. We cast the problem in a spatial model of the power sector where generators can develop new capacities, the transmission system is organized on a flowgate basis, emission allowances are auctioned, except possibly for industries, and traded. The consumer market is decomposed in two segments. Industries purchase electricity according to some form of average cost price, the rest of the market is supplied at marginal cost. These equilibrium models are non convex. We present the models and discuss their properties. Companion papers report policy implications.

The inception of the Emission Trading System in Europe (EU-ETS) has made power price more expensive. This affects the competitiveness of electricity intensive industrial consumers and may force them to leave Europe. Taking up of a proposal of the industrial sector, we explore the possible application of special contracts, based on the average cost pricing system, which would mitigate the impact of CO2 cost on their electricity price. The model supposes fixed generation capacities. A companion paper treats the case with capacity expansion. We first consider a reference model representing a perfectly competitive market where all consumers (households and industries) are price-takers and buy electricity at the short-run marginal cost. We then change the market design assuming that large industrial consumers pay power either at a single or at a nodal average cost price. The analysis of these problems is conducted with simulation models applied to the Northwestern European market. The equilibrium models developed are implemented in the GAMS environment.

Former generation capacity expansion models were formulated as optimization problems. These included a reliability criterion and hence guaranteed security of supply. The situation is different in restructured markets where investments need to be incentivised by the margin resulting from electricity sales after accounting for fuel costs. The situation is further complicated by the payments and charges on the carbon market. We formulate an equilibrium model of the electricity sector with both investments and operations. Electricity prices are set at the fuel cost of the last operating unit when there is no curtailment, and at some regulated price cap when there is curtailment. There is a CO2 market and different policies for allocating allowances. Todays situation is quite risky for investors. Fuel prices are more volatile than ever; the total amount of CO2 allowances and the allocation method will only be known after investments has been decided. The equilibrium model is thus one under uncertainty. Agents can be risk neutral or risk averse. We model risk aversion through a CVaR of the net margin of the industry. The CvaR induces a risk neutral probability according to which investors value their plants. The model is formulated as a complementarity problem (including the CVaR valuation of investment). An illustration is provided on a small problem that captures the essence of today electricity world: a choice restricted to coal and gas, a peaky load curve because of wind penetration, uncertain fuel prices and an evolving carbon market (EU-ETS). We show that we might have problem of security of supply if we do not implement a capacity market.

Le texte est structuré comme suit : la première section présente un exemple de contrat transfrontalier auquel on se référera dans la suite. La section expose également les deux thèmes qui seront défendus : tout d’abord, il est difficile de créer des marchés électriques en nombre suffisant et fonctionnant bien ; ensuite, il ne sert à rien d’augmenter encore cette difficulté en repassant par les mêmes erreurs d’organisation de marchés que d’autres ont commises et documentées. La deuxième section aborde le premier thème : bien que le contrat qui sert d’exemple soit très simple, on ne peut actuellement le valoriser sur la base des produits actuellement commercialisés sur les marchés, qu’ils soient organisés ou de gré à gré. Les marchés de ces produits n’existent pas ou sont encore en développement. La troisième section veut explorer les raisons de cette situation. Enfin, cet article se réfère également à l’expérience européenne, c’est-à-dire aux démarches visant à intégrer les marchés électriques en Europe. The first section presents a cross-boundary type of contract which will serve as a reference further on and also gives a brief outline of the two points that will be defended here : first, creating a sufficient number of efficient electricity markets turns out to be difficult ; Second, increasing this difficulty by repeating previous well documented organisational mistakes seems purposeless. Addressing the first topic, the second section shows that however simple the reference contract may be, it cannot for the time being be used for existing commercial products, whether on organised or on mutual agreement markets. Markets for such products do not yet exist or are still in a development stage. The third section explores the reasons for this situation. Finally, the paper also refers to the European experience and the steps taken to integrate electricity markets in Europe.

The restructuring of the gas industry did not so far generate the same modeling activity as in electricity. While the literature of activity in electricity market models is now abundant, it is still rather scant on the gas side. This paper surveys some of the existing models and attempts to take advantage of the wealth of knowledge available in electricity in order to develop relevant models of restructured gas markets. The presentation is in three parts. The first one gives a bueprint of the market architectures inherited from the European and North American gas legislation. It also introduces a prototype optimization model and its interpretation in terms of perfect competition between agents operating on the restructured market. The second part extends the model to the case where marketers have market power. The third part considers more complex issues related to regulation of access to the network and existence of market power with different types of agents. Equilibrium models are commonly formulated as complementarity problems and the same mathematical programming framework is adopted here. Many models are single stage; there are generally easy to formulate and well known computationally. But many phenomena require two stage models that are much more intricate and on which much less is known. The paper is thus also aimed at pinpointing possible avenues for mathematical programming research.

The integration of national electricity systems into a single internal European electricity market is not progressing well with the result that the level of competition in the sector remains unsatisfactory. This had led to proposals to apply ex ante remedies that directly bear on the structure of national incumbents. These measures involve quantitative recommendations such as virtual auctioning of capacity or divestitures that increase the number of competing firms. The evaluation of these measures partly relies on computable oligopoly models of the restructured electricity sector. This paper analyses the recent literature of these models and concludes that they are not currently capable of providing the degree of legal and regulatory certainty that the importance of these ex ante remedies requires. The state of the art in these models is such that their results reflect more a set of non-testable assumptions than observed facts or unambiguous theory. More academic work is necessary before these models can be applied in a legal or regulatory context. The conclusion is that this work on the structure of national electricity market distracts from the fundamental objective to introduce competition in the power sector by integrating the national markets into a single electricity market.

We present a model of generation and network investment in a competitive electricity system. The model focuses on the duality of long-and short-term locational signals introduced in the European Regulation 1228/2003 for enhancing cross border trade of electricity among Member States. The model assumes that the market consists of spot and transmission submarkets. Generators, consumers and a TSO operate on that market; none of these agents has market power. Lumpiness of investments is one of the problems that may render generation and network adequacy difficult to achieve. We take up this question and apply some formalism formerly developed by O'Neill and co-authors for the unit commitment problem in order to construct multipart tariffs that insure the adequate development of the resources both in generation and the grid. In the process, we recover the standard nodal pricing as part of that multipart tariff. We address the questions of cost reflectiveness and non discrimination imposed by Regulation 1228/2003.

This paper analyzes the properties of three capacity games in an oligopolistic market with Cournot players. In the first game, capacity and the operation of that capacity is determined simultaneously. This is the classic open-loop Cournot game. In the second game capacity is decided in the first stage and the operation of that capacity is determined in the second stage. The first stage decision of each player is contingent on the solution of the second-stage game. This is a two-stage, closed-loop game. We show that when the solution exists, it is the same as the solution in the first game. However, it does not always exist. The third game has three stages with a futures position taken between the capacity stage and the operations stage and is also a closed-loop game. As with the second game, the equilibrium is the same as the open-loop game when it exists. However, the conditions for existence are more restrictive once a futures market is added. When both games have an equilibrium, the solution values are identical. The results are very different from games with no capacity stage as studied by Allaz and Vila (1993), which have been used to argue that futures markets can ameliorate market power.

An efficient congestion management system is a necessary condition to remove obstacles to the cross border trade of electricity in Europe and hence to move towards an internal electricity market. Locational marginal pricing (LMP) is progressively becoming the benchmark of congestion management in the United States. It is conceptually simple, compatible with basic economic theory and physical realities, and effective in practice. Proposals for congestion management in Europe depart in several ways from this benchmark. We discuss these proposals and illustrate some of their inefficiences. A special emphasis is placed on the restrictions to trade implied by the implementation of zonal approaches.

The paper analyses various proposals for the organization of regional electricity transmission in terms of the market incompleteness that they may implicitly assume. Elementary notions of variational inequalities constitute the analytical tool used throughout the paper. The discussion is conducted with reference to the flowgate debate in the US and Europeanproposals for the organization of cross border electricity trade. This first part of the paper discusses market incompleteness in the forward (day ahead) market. The main results can be summarized as follows. An energy market without a market for transmission services is incomplete and hence inefficient. The nodal and flowgate models complete the market when one does not consider contingencies. One can define a notion of transmission capacity (called an extended flowgate) by aggregating line capacities using spot prices. This transmission capacity completes the market and reduces the number of necessary flowgates (possibly to one). But these extended flowgates have variable capacities. As in the case of the nodal model, extended flowgates can accommodate contingencies in the forward market.

The paper extends our previous analysis of market incompleteness to the case where there exist both a forward and real time market. The discussion is conducted with reference to a two-stage framework commonly used in stochastic programming and finance, but also familiar to the power industry. The paper considers two market designs. The first organization assumes that physical transmission services are auctioned in the forward market. The second organization supposes a financial market of transmission services. We recover the known perfect hedging property of nodal pricing and show that the flowgate model does not share this property. A standard proposition in finance is that market completeness requires that the number of tradable instruments is equal to or exceeds the number of risk factors. We show that none of the nodal or flowgate models satisfy this property. Other instruments, of the option type, should thus be introduced in these systems in order to better trade risk and complete the market.

Investments in generation capacity in restructured electricity systems remain a relatively unexplored subject in the modeling community. We consider three models that differ by their underlying economic assumptions and the degree to which they depart from the old capacity expansion representations. The first model assumes a perfect, competitive equilibrium. It is computationally very similar to the old capacity expansion models even if its economic interpretation is different. The second model (open-loop Cournot game) extends the Cournot model that is sometimes used for modeling operations in restructured electricity systems to include investments in new generation capacities. This model can be interpreted as describing investments in an oligopolistic market where capacity is simultaneously built and sold on long-term contracts when there is no spot market (Power Purchase Agreements). The third model (closed-loop Cournot game) separates the investment and sales decision. It describes a situation where investments are decided in a first stage and sales occur in a second stage, both taking place in oligopolistic markets. The second stage is a spot market. This makes the problem a two-stage game and corresponds to investments in merchant plants where the first stage equilibrium problem is solved subject to equilibrium constraints. Because two-stage models are relatively unusual in discussions of electricity, we characterize the properties of this game and compare them with those of the open-loop game. We show that despite some important differences, the open and closed-loop games share many properties. One of the important results is that the solution of the closed-loop game, when it exists, falls between the solution of the open-loop game and the competitive equilibrium.