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Investment coordination in network industries: The case of electricity grid and electricity generation
Abstract
Liberalization of network industries frequently separates the network from the other parts of the industry. This is important in particular for the electricity industry where private firms invest into generation facilities, while network investments usually are controlled by regulators. We discuss two regulatory regimes. First, the regulator can only decide on the network extension. Second, she can additionally use a “capacity market” with payments contingent on private generation investment. For the first case, we find that even absent asymmetric information, a lack of regulatory commitment can cause inefficiently high or inefficiently low investments. For the second case, we develop a standard handicap auction which implements the first best under asymmetric information if there are no shadow costs of public funds. With shadow costs, no simple mechanism can implement the second best outcome.
... Sauma and Oren (2006) and Pozo et al. (2013) show that a proactive transmission planner can induce generation companies to invest in a more socially efficient manner by anticipating investments in generation capacity. Höffler and Wambach (2013) show that generation investment can lead to overinvestment or underinvestment in the electricity grid when private investors do not take the costs and benefits of network extensions into account. They also show that a capacity market can incentivize private investors to make socially efficient locational choices. ...
The unbundling of formerly vertically integrated utilities in liberalized electricity markets led to a coordination problem between investments in the regulated electricity grid and investments into new power generation. At the same time investments into new generation capacities based on weather dependent renewable energy sources such as wind and solar energy are increasingly subsidized with different support schemes. Against this backdrop this article analyzes the locational choice of private wind power investors under different support schemes and the implications on grid investments. I find that investors do not choose system optimal locations in feed-in tariff schemes, feed-in premium schemes and subsidy systems with direct capacity payments. Consequently, inefficiencies arise if transmission investment follows wind power investment. A benevolent transmission operator can implement the first-best solution by anticipatory investment behavior, which is however only applicable under perfect regulation. Alternatively a location dependent network charge for wind power producers can directly influence investment decisions and internalize the grid integration costs of wind power generation.
... To this end, however, we need to make some common abstractions from technical details such as the reduction to two regions (cf. Höffler & Wambach 2013, Oliver et al. 2014). However, each of the two regions may be interpreted as an aggregate of a network of multiple generation and load nodes connected via a single transmission line. ...
Electricity from renewable sources often cannot be generated when and where it is needed. To deal with these temporal and spatial discrepancies, one frequently proposed approach is to expand storage capacities and transmission grids. It is often argued that the two technologies substitute each other, such that deploying one reduces the need for the other. Using a theoretical model, we show that storage capacities and transmission grids can also be complements if electricity system costs are minimized. We present the conditions that determine the kind of interdependence at specific storage locations: the characteristics of transmission congestion and the alignment of marginal generation costs between adjacent regions. By applying our theoretical insights to Italian power system data, we obtain empirical evidence that storage and transmission can act as either substitutes or complements. Planners of long-lasting and costly infrastructure can use the results to avoid design errors such as a misplacement of storage within the system.
... Sauma and Oren (2006) and Pozo et al. (2013) show that a proactive transmission planner can induce generation companies to invest in a more socially efficient manner by anticipating investments in generation capacity. Höffler and Wambach (2013) show that generation investment can lead to overinvestment or underinvestment in the electricity grid when private investors do not take the costs and benefits of network extensions into account. They also show that a capacity market can incentivize private investors to make socially efficient locational choices. ...
The unbundling of formerly vertically integrated utilities in liberalized electricity markets led to a coordination problem between investments in the regulated electricity grid and investments into new power generation. At the same time investments into generation capacities based on weather-dependent renewable energy sources such as wind and solar energy are increasingly subsidized with different support schemes. Against this backdrop this article analyzes the locational choice of private wind power investors under different support schemes and the implications on grid investments. I find that investors do not choose system optimal locations in feed-in tariff schemes, feed-in premium schemes and subsidy systems with direct capacity payments. Consequently, inefficiencies arise if transmission investment follows wind power investment. A benevolent transmission operator can implement the first-best solution by anticipatory investment behavior, which is however only applicable under perfect regulation. Alternatively a location-dependent network charge for wind power producers can directly influence investment decisions and internalize the grid integration costs of wind power generation.
... On the one hand, issues of timing (e.g., due to uncertainty or commitment) in settings consisting of multiple players (such as generation and transmission) have been addressed. Höffler and Wambach (2013) find that long-term commitment of a benevolent TSO may lead to inefficient investment decisions due to the locational decisions of investments in generation. In contrast, Sauma and Oren (2006) and Rious et al. (2009) formulate the coordination problem between a generation and a transmission agent as a decomposed problem, and find that a prospective coordinated planning approach as well as transparent price signals entail efficiency gains, though some inefficiencies remain and the first best is not realized. ...
In liberalized power systems, generation and transmission services are unbundled, but remain tightly interlinked. Congestion management in the transmission network is of crucial importance for the efficiency of these inter-linkages. Different regulatory designs have been suggested, analyzed and followed, such as uniform zonal pricing with redispatch or nodal pricing. However, the literature has either focused on the short-term efficiency of congestion management or specific issues of timing investments. In contrast, this paper presents a generalized and flexible economic modeling framework based on a decomposed inter-temporal equilibrium model including generation, transmission, as well as their inter-linkages. The model covers short-run operation and long-run investments and hence, allows to analyze short and long-term efficiency of different congestion management designs that vary with respect to the definition of market areas, the regulation and organization of TSOs, the way of managing congestion besides grid expansion, and the type of cross-border capacity allocation. We are able to identify and isolate implicit frictions and sources of inefficiencies in the different regulatory designs, and to provide a comparative analysis including a benchmark against a first-best welfare-optimal result. To demonstrate the applicability of our framework, we calibrate and numerically solve our model for a detailed representation of the Central Western European (CWE) region, consisting of 70 nodes and 174 power lines. Analyzing six different congestion management designs until 2030, we show that compared to the first-best benchmark, i.e., nodal pricing, inefficiencies of up to 4.6% arise. Inefficiencies are mainly driven by the approach of determining cross-border capacities as well as the coordination of transmission system operators’ activities.
... There are some exceptions, such as the work of Sauma and Oren [20] and Pozo et al. [21], who apply equilibrium models to analyze the implications of network investments on social welfare, taking into account the effects of grid congestion on generators investments and production decisions. In the same line, H€ offler and Wambach [22] use a two-node network model to analyze the coordination of grid and generation investments under different regulatory regimes and its implications in terms of social welfare. Nevertheless, these optimization/equilibrium models require strong assumptions that limit the analysis of systems away from equilibrium, such as the electricity markets' transition towards integration, and are conceived for national markets, where the same policies are applied at both ends of the interconnector. ...
This paper evaluates investment incentives for wind power under two market designs: uniform and nodal pricing. An electricity system model is developed, that allows for investments in wind power capacities while carefully accounting for static transmission grid constraints. Wind power capacities are assumed to reach the same expansion target by 2030 under both market designs. The results show that the introduction of nodal prices leads to investments in wind power plants shifting to locations with lower wind yield. The amount of electricity fed into the grid from wind power plants, however, is higher under nodal pricing as curtailment is reduced by two-thirds. Furthermore, grid-optimal wind locations are shown to require higher direct subsidy payments but decrease yearly variable supply costs by 1.5% in 2030. Yet distributional effects present an obstacle to the introduction of a nodal pricing regime, with about 75% of German demand facing an increase in electricity costs of about 5%. To mitigate the distorted investment signals arising from uniform pricing regimes, restricting investments within grid expansion areas proves to be more promising than including latitude-dependent generator-component in the grid tariff design.
This paper evaluates investment incentives for wind power under uniform and nodal pricing. An electricity system model is developed, which allows for investments into wind power while considering transmission grid constraints in detail. Targeting equally high wind capacities under nodal and uniform pricing until 2030, locations of new wind power plants shift towards sites with lower wind yield under nodal prices. The wind energy fed into the grid, though, is higher under nodal pricing since curtailment is cut to a third. Grid-optimal wind locations require higher subsidy payments but decrease yearly variable supply costs by 1.5% in 2030. However, distributional effects are an obstacle to implementing nodal pricing, where about 75% of German demand faces electricity costs increase of about 5%. For mitigating distorted investment signals of uniform pricing, implementing investment restrictions within grid expansion areas prove to be more promising than a latitude-dependent generator-component in the grid tariff design.
In this paper we analyze a uniform price day-ahead electricity spot market that is followed by redispatch in the case of network congestion. We assume that the transmission system operator is incentivized to minimize redispatch cost and compare cost-based redispatch (CBR) to market-based redispatch (MBR) mechanisms. For networks with at least three nodes we show that in contrast to CBR, in the case of MBR incentives to minimize redispatch cost are in general not efficient in the context of our short-run analysis. This obtains both for pay-as-bid as well as locational marginal prices used for MBR compensation. As we demonstrate, moreover, in case of MBR the possibility of the transmission system operator to inefficiently reduce redispatch cost at the expense of decreased overall welfare can be driven both by the electricity supply side and the electricity demand side.Our results highlight a novel and important aspect regarding the design and the desirability of congestion management regimes in liberalized electricity markets.
For over twenty years, electricity market liberalization has advanced short-term market efficiency in wholesale markets, but little progress has been made on coordinated transmission and generation investments. With fast penetration of renewables, widespread of distributed energy resources and emergence of smart-grid and energy storage technologies, the stake is growing significantly higher for the long-term efficiency of liberalized wholesale markets with an aging transmission infrastructure.
This paper presents a methodology based on a general framework of two-stage stochastic optimization model for analyzing interactions between transmission and generation investments. The methodology features economic effects of prices, incentives and welfare impacts under alternative coordination approaches and cost recovery mechanisms. Application to scenarios under efficient coordination, merchant transmission, and sequential coordination are illustrated using a simple radial transmission network. Interestingly, a Boiteux-Ramsey cost sharing rule produces energy prices and social welfare impacts that appear essentially indistinguishable from those obtained under efficient coordination.
Nuclear power is an important pillar in electricity generation in France. However, the French nuclear power plant fleet is ageing, and the possibility of reducing the technology's share in power generation or even a complete phase-out has been increasingly discussed. This paper focuses on three inter-related questions: First, what are the costs of phasing-out nuclear power in France? Second, who has to bear these costs, i.e., how much of the costs will be passed on to the rest of the European power system? And third, what effect does the uncertainty regarding future nuclear policy in France have on system costs? Applying a stochastic optimization model for the European electricity system, the analysis showed that additional system costs in France of a nuclear phase-out amount up to 76 billion €2010. Additional costs are mostly borne by the French power system. Surprisingly, the analysis found that the costs of uncertainty are rather limited. Based on the results, it can be concluded that a commitment regarding nuclear policy reform is only mildly beneficial in terms of system cost savings.
In the ongoing energy policy debate various options to reduce the necessary network expansion in Germany are discussed. Our contribution analyses two possibilities to reduce network expansion through relatively moderate adjustments of the regulatory framework: First, the consideration of redispatch (in the furture) as a possible substitute for network expansion and, second, efficient feed-in management. Our computational results show that both measures achieve a considerable reduction of necessary network expansion. Moreover, the combination of both measures hast he potential to make a substantial part of the currently planned network expansion dispensable. We furthermore show that both measures yield moderate welfare gains, which would also be reflected in lower electricity prices. Again, the combination of both measures generates a substantial welfare gain, namely 83% of the maximal possible welfare gain in the first best benchmark where all investment and production decisions are taken optimally.
This paper argues against the rapid implementation of capacity mechanisms in Germany. There is no systematic, non-temporary market failure in the German wholesale electricity market which could justify such a Government intervention. Neither the low elasticity of demand nor debatable public good characteristics nor the potentially missing acceptance of price spikes can support the idea of that the energy only market may fail to guarantee reliability of supply. In addition, there are currently no resilient signs of any shortage of supply. In contrast, the German wholesale electricity market is still characterized by over-capacities. The worldwide experience with capacity mechanisms also demonstrates most of all that no capacity market design is ever stable, but subject to change in often quite short intervals. Potential low-cost options to safeguard security of supply include a strategic reserve against generation failures. In addition, the Federal Cartel Office should correct its position that dominant firms must not offer electricity at a price above the short-run marginal cost. Such a prescription forecloses the market and chokes off investment and would in most other cases be regarded as an anticompetitive foreclosure strategy of a dominant firm.
Mexico is in the midst of enacting new energy market reform. After one year of presidential proposals, 21 laws were enacted in August, 2014. The analysis shows inconsistencies and lacunae in defining an open electricity market. According to the proposed reform, incumbent Comisión Federal de Electricidad (CFE) will keep transmission and distribution vertically integrated with newly created subsidiaries subject to third-party subcontracting, while private generation participants will compete in a wholesale market operated by Centro Nacional de Control de Energía (CENACE). Following an institutional economics approach and a framework to account for transition and coordination issues, the problem of misaligned incentives is analyzed along two governance dimensions: regulatory failure and market foreclosure. The research predicts negative effects of energy reform on grid investments and government coordination in Mexico.
Economical and reliable supplies of electricity make possible many of the services that we associate with modern life. From
electric lights and microwave ovens, to television, telephones, and computers, electricity is a critical input supporting
a wide range of consumption, transportation and production activities. The electricity sector is also a major manufacturing
sector, accounting for about 210 billion of annual sales, about210 billion of annual sales, about 40 billion in annual investment and 35 percent of U.S. primary
energy use.
Electricity transmission pricing and transmission grid expansion have received increasing attention in recent years. There
are two disparate approaches to transmission investment: one employs the theory based on long-run financial rights (LTFTR)
to transmission (merchant approach), while the other is based on the incentive-regulation hypothesis (regulatory approach).
In this paper we consider the elements that could combine the merchant and regulatory approaches in a setting with price-taking
electricity generators and loads. The monopoly transmission firm (Transco) is regulated through benchmark or price regulation
to provide long-term investment incentives. The two-part tariff approach used can be analyzed analytically only for well-behaved
cost and demand functions. We explore a series of simplified transmission grids to argue that in a variety of circumstances
those functions could have reasonable economic properties. The results suggest directions for further research to explore
the properties of the cost functions and implications for design of practical incentive mechanisms and the integration with
merchant investment in organized markets with LTFTRs.
KeywordsElectricity transmission-Financial transmission rights-Incentive regulation-Loop-flow problem
JEL ClassificationD24-L51-L94
While the transmission grid is essential to the operation of well-functioning electric power markets, it appears to be lacking
in many regions. This article investigates the causes of this situation, that reviews the main prescriptions of the academic
literature, and compares them with experience from sixteen jurisdictions that have restructured their power industry in the
last twenty years. We find that vertical separation may be necessary, but is not sufficient to induce grid expansion: a well-designed
incentive scheme is also required. When both vertical separation and specific incentives are present, significant congestion
reduction is observed.
A fully unbundled, regulated network firm of unknown efficiency level can untertake unobservable effort to increase the likelihood of low downstream prices, e.g. by facilitating downstream competition. To incentivize such effort, the regulator can use an incentive scheme paying transfers to the firm contingent on realized downstream prices. Alternatively, the regulator can force the firm to sell the following forward contracts: the firm pays the downstream price to the owners of a contract, but recieves the expected value of the contracts when selling them to a competivitve financial market. We compare the two regulatory tools with respect to regulatory capture: if the regulator can be bribed to suppress information on the underlying state of the world (the basic propability of high downstream prices, or the type of the firm), optimal regulation uses forward contracts only.
We analyse a situation where a monopolist is selling an indivisible good to risk-neutral buyers who only have an estimate
of their private valuations. The seller can release, without observing, certain additional signals that affect the buyers'
valuations. Our main result is that in the expected revenue-maximizing mechanism, the seller makes available all the information
that she can, and her expected revenue is the same as it would be if she could observe the part of the information that is
“new” to the buyers. We also show that this mechanism can be implemented by what we call a handicap auction in interesting applications. In the first round of this auction, each buyer picks a price premium from a menu offered by
the seller (a smaller premium costs more). Then the seller releases the additional signals. In the second round, the buyers
bid in a second-price auction where the winner pays the sum of his premium and the second highest non-negative bid. In the
case of a single buyer, this mechanism simplifies to a menu of European call options.
In this article we use transaction cost economics to analyze the determinants of performance of privatized utilities in different political and social circumstances. Case studies are drawn from telecommunications regulation in Argentina, Chile, Jamaica, the Philippines and the United Kingdom. We explore how political institutions interact with regulatory processes and economic conditions in determining the potential for administrative expropriation or manipulation, and hence affect the sector's economic performance. We find that performance can be satisfactory with a wide range of regulatory procedures, as long as arbitrary administrative action can be restrained. We find also that regulatory credibility can be developed in unpropitious environments, that without such commitment long-term investment will not take place, that achieving such commitment may require inflexible regulatory regimes, that in some cases public ownership of utilities is the default mode of organization, and furthermore, that it may be the only feasible alternative. Copyright 1994 by Oxford University Press.
This paper analyzes the incentives for electric grid investment that result from various proposed transmission network property regimes. In particular, we focus on "transmission congestion contracts" within a contract network regime such as proposed by William Hogan. We formalize a rule for awarding these new property rights to investors and show that, under certain conditions, this contract network approach can effectively deter detrimental investments, some of which are encouraged under other regimes. However, when these conditions are not met, market participants may still find it profitable to undertake network alterations which are detrimental to the network as a whole. Copyright 1996 by Kluwer Academic Publishers
The U.S. electricity sector is going through dramatic changes. The changes are expanding competition in the generating segment of the industry, making it possible for consumers to choose among competing generation service suppliers, and reforming the regulation of remaining monopoly segments. The paper discusses current industry structure and regulation, its historical performance, and the sources of political pressures for change. It examines important industry restructuring and regulatory reform issues, including the organization of competitive generation markets, transmission access and pricing, generation market power, and the application of incentive regulation mechanisms to the transmission and distribution segments. Copyright 1997 by American Economic Association.
We consider three explanations for public ownership: public interest, regulation, and a transaction cost interpretation. We employ a large dataset containing information on the municipal acquisition of U.S. private water companies between 1897 and 1915. Those data allow us to isolate the effects of high water rates, water quality, financial difficulties, extensiveness of distribution system, and the like in determining the probability of subsequent municipal takeover of companies that were private in 1897. After controlling for such factors, we find evidence consistent with a transaction cost interpretation of municipal acquisition. We find relatively little support for regulation-based or public interest interpretations. Our evidence indicates that municipalities were unable to credibly precomrnit to not expropriating value from private water companies once investments were made, resulting in a rational reduction in investment in water provision by private companies. Local governments, in turn, used this rational underinvestment as a pretext for municipalizing private water companies.
I develop and test three theories of public ownership: a small markets hypothesis; a commitment hypothesis; and a patronage hypothesis. The empirical analysis employs a cross section of 1,274 public and private gas companies operating in 1911. With these data, I find the following patterns: gas companies located in small towns were more likely to have been municipally owned than those in large towns; gas companies regulated by city councils were more likely to have been municipally owned than companies that were unregulated; and gas companies regulated by state commissions were less likely to have been municipally owned than companies that were unregulated. Placed in their historical context, these results support the small markets and property rights interpretations of public ownership.
Unlike other public utilities, most water in the United States is supplied by publicly owned and operated waterworks. The predominance of the public sector in the supply of water was not always the case, however; private firms dominated US water supply throughout most of the 19th century. This article analyzes the puzzle of why water and sanitation systems were the only major utilities to become predominantly public by, first, reexamining historical accounts of the problems of contracting for water services in light of modern theories of economic organization and, then, evaluating hypotheses derived from those accounts using data on 373 waterworks serving US municipalities with populations over 10,000 in 1890. Among other results, municipal ownership is found to be related to the distribution of population and commerce within a city in ways that suggest that frictions between cities and private companies over system extensions and improvements played a significant role in the shift to municipal ownership. The Author 2010. Published by Oxford University Press on behalf of Yale University. All rights reserved. For Permissions, please email: journals.permissions@oxfordjournals.org, Oxford University Press.
Power generation and transmission are complementary activities that must be coordinated to ensure an optimal use and development of the transmission network. This coordination is today more difficult in a liberalized system, because of unbundling and the freedom for investors to choose their generation technologies (Joskow, 2006). Shorter investment time between generation and network create uncertainty for the network planning and congestions. In the economic literature, the efficiency of anticipating generation investment has been under-evaluated assuming that it is a cost free activity. Our model evaluates the effect of anticipation costs and defines in which cases the previous results by Sauma and Oren (2006, 2007) could still hold.
Designing regulatory contracts for the operators of power transmission networks has become a critical policy issue in the United States. In this paper, a regulatory contract is proposed that induces network operators to optimally expand the grid, which is crucial for the emergence of efficient wholesale power markets, while also satisfying the other traditional regulatory objectives. The proposed mechanism is readily implementable, since it builds on a contract currently in place in England and Wales.
This paper examines the incentives that generation firms have in restructured electricity markets for supporting long-term transmission investments. In particular, we study whether generation firms, which arguably play a dominant role in the restructured electricity markets, have the incentives to fund or support incremental social-welfare-improving transmission investments. We examine this question in a two-node network and explore how such incentives are affected by the ownership of financial transmission rights (FTRs) by generation firms. In the analyzed two-node network, we show both (i) that the net exporter generation firm has the correct incentives to increase the transmission capacity incrementally up to a certain level and (ii) that, although a policy that allocates FTRs to the net exporter generation firm can be desirable from a social point of view, such a policy would dilute the net-importer-generation-firm's incentives to support transmission expansion. Moreover, if all FTRs were allocated or auctioned off to the net exporter generation firm, then it is possible to increase both consumer surplus and social welfare while keeping the net exporter generation firm revenue neutral.
We argue that a capacity market is needed in most restructured electricity markets, and present a design that avoids the many problems found in the early capacity markets. The proposed locational capacity market pays suppliers based on their demonstrated ability to supply energy or reserves in shortage hours - hours in which there is a shortage of operating reserves. Thus, only supply that contributes to reliability is rewarded. The capacity price responds to market conditions. When capacity is scarce the capacity price is high; when capacity is plentiful the capacity price is low or zero. Market power in the capacity market is addressed by setting the capacity price based on actual capacity, rather than bid capacity, so generators cannot increase the capacity price by withholding supply. Ex post peak energy rents (the short-run energy and reserve profits of a benchmark peaking unit) are subtracted from the capacity price. Thus, a supplier does not have an incentive to create real-time shortages - the high shortage price resulting from a shortage is subtracted from the capacity price, so there is no net gain from the high price. By defining a capacity product closely tied to reliability and directly addressing market power both in the capacity market and in the spot energy market, the proposed design creates a market with reduced regulatory and market risk for investors. In the long-run this saves consumers money.
We consider three explanations for public ownership: public interest, regulation, and a transaction cost interpretation. We employ a large dataset containing information on the municipal acquisition of U.S. private water companies between 1897 and 1915. Those data allow us to isolate the effects of high water rates, water quality, financial difficulties, extensiveness of distribution system, and the like in determining the probability of subsequent municipal takeover of companies that were private in 1897. After controlling for such factors, we find evidence consistent with a transaction cost interpretation of municipal acquisition. We find relatively little support for regulation-based or public interest interpretations. Our evidence indicates that municipalities were unable to credibly precommit to not expropriating value from private water companies once investments were made, resulting in a rational reduction in investment in water provision by private companies. Local governments, in turn, used this rational underinvestment as a pretext for municipalizing private water companies. Copyright 2003, Oxford University Press.
Traditional methods of evaluating transmission expansions focus on the social impact of the investments based on the current
generation stock which may include firm generation expansion plans. In this paper, we evaluate the social welfare implications
of transmission investments based on equilibrium models characterizing the competitive interaction among generation firms
whose decisions in generation capacity investments and production are affected by both the transmission investments and the
congestion management protocols of the transmission system operator. Our analysis shows that both the magnitude of the welfare
gains associated with transmission investments and the location of the best transmission expansions may change when the generation
expansion response is taken into consideration. We illustrate our results using a 30-bus network example.
As competition is introduced into the electric power industry, access and pricing policy for transmission will play a pivotal role in shaping future market structure and performance. The externalities associated with the loop flow phenomenon in an electric power network constitute a significant barrier to the formation of efficient markets for electricity and transmission services. In this paper, we present a new approach to the design of an efficient market mechanism for transmission access that resolves these externalities. Under a trading rule that combines the Coasian and the Pigouvian principles to resolution of externalities, property rights are defined so that a competitive market could be established for transmission services and electricity to achieve a social optimum within a power pool. We characterize a dynamic trading process which is Lyapunov stable and always converges to a competitive equilibrium. Finally, we discuss some practical applicability and long-term investment issues. Copyright 1996 by Kluwer Academic Publishers
This paper argues that a variety of imperfections in wholesale "energy-only" electricity markets lead to generators earning net revenues that are inadequate to support investment in a least cost portfolio of generating capacity and to satisfy consumer preferences for reliability. Theoretical and numerical examples are used to illustrate the sources of this "missing money" problem. Improvements in "energy-only" wholesale electricity markets, especially those that improve pricing when capacity is fully utilized, can reduce the magnitude of the missing money problem. However, these improvements are unlikely to fully ameliorate it. Forward capacity obligations and associated auction mechanisms to determine capacity prices are necessary to restore appropriate wholesale market prices and associated investment incentives to support the optimal portfolio of generating investments. The deficiencies of the original capacity payment mechanisms adopted in the US are discussed and the necessary improvements identified.
We examine the performance attributes of a merchant transmission investment framework that relies on 'market driven' investment to increase transmission network capacity needed to support competitive wholesale markets for electricity. Under a stringent set of assumptions, the merchant investment model has a remarkable set of attributes that appears to solve the natural monopoly problem and the associated need for regulating electric transmission companies. We expand the merchant model to incorporate several attributes of wholesale power markets and transmission networks that the merchant model ignores. These include market power in wholesale electricity markets, lumpiness in transmission investment opportunities, stochastic attributes of transmission networks and associated property rights definition issues, strategic behavior by potential merchant transmission investors and issues related to the coordination of transmission system operators and merchant transmission owners. Incorporating these more realistic attributes of transmission networks and the behavior of transmission owners and system operators leads to the conclusion that several potentially significant inefficiencies may result from reliance on the merchant transmission investment framework. Accordingly, it is inappropriate for policymakers to assume that they can avoid dealing with the many challenges associated with stimulating efficient levels of investment in electric transmission networks by adopting the merchant model. Copyright Blackwell Publishing Ltd. 2005.
The convergence of market design for adequate generating capacity
- P Cramton
- S Stoft