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In the regulation of network tariffs, the compensation for the opportunity costs of capital through the Weighted Average Costs of Capital (WACC) plays a crucial role. Determining the appropriate level for the WACC is, though, problematic because of the uncertainty about the future conditions in capital markets. When the WACC is set above the future opportunity costs of capital, consumers will pay too much, while when the WACC is below that level, network operators may be unable to finance investments affecting quality of network services. In this paper, we explicitly take this uncertainty into account when we determine the optimal WACC for the tariff regulation of an electricity network. By trading off consumer surplus and expected disruption costs in the electricity grid, we conclude that from a social-welfare perspective in most cases the optimal WACC in tariff regulation is above the historical mean costs of capital. Only in case of high uncertainty about the true costs of capital while network operators are able to quickly increase investment levels, the optimal WACC is below the historical mean because then it is less likely that the WACC is constantly insufficient to cover actual costs of capital. However, when network operators cannot quickly increase investment levels the optimal WACC is always above the historical mean cost of capital. [ABSTRACT FROM AUTHOR]

Residential electricity competition is under investigation in a number of U.S. states due to alleged market imperfections including consumer behavior that is supposedly inconsistent with rational, economic decision-making. In this paper, I examine these issues and use a panel data of distribution utilities in Illinois during the period 2011–2017 to estimate demand models for regulated and competitive electricity services. I find that residential electricity consumers in Illinois are acting in a manner consistent with standard consumer behavior theory, with price elasticity of demand estimates that are generally in line with those in the literature, ranging between − 0.40 and − 0.60. Importantly, I find evidence that customers served by competitive suppliers are sensitive to the regulated default service price. Specifically, I find that a 1% decrease in the regulated default service price will lead to approximately 0.5% of customers served by competitive suppliers switching to the regulated default service. These findings call into question some of the underpinnings of policymakers' critique of residential electricity competition. [ABSTRACT FROM AUTHOR]

In 2016, the UK Competition and Markets Authority (CMA) found that "weak customer response" enabled incumbent UK energy retailers to set higher and discriminatory prices to residential customers. The CMA estimated the associated higher prices constituted a customer detriment in the range £1.4 bn to £2 bn per year. Although the CMA recommended against a price cap on most domestic energy tariffs, the size of the detriment and public concern about "rip-off energy tariffs" nonetheless led the Government to impose a price cap as from January 2019. This paper examines the CMA's calculation of customer detriment and suggests that it is inconsistent with CMA Guidelines and unprecedented with respect to its nature, magnitude and policy impact. Alternative more realistic calculations suggest that any detriment would have been nearly an order of magnitude lower, so that a price cap was inappropriate. This raises a number of questions about the CMA's approach. [ABSTRACT FROM AUTHOR]

We extend the theory of peak-load pricing by considering that the production with different technologies can be adjusted within their capacity at different speeds. In the established analysis, all production decisions can be made after the random variables realize. In our setting, in contrast, some decisions are made before, others after. This is important, e.g., when increasing capacities of renewables are integrated in electricity systems worldwide. We consider fixed load and three types of capacities: partially dispatchable capacity (e.g., nuclear power-plants) needs to be scheduled ahead of actual production, non-dispatchable capacity (e.g., wind turbines) produces randomly, and highly-dispatchable capacity (e.g., gas turbines) can instantly adjust. If capacities differ in their dispatchability, some standard results of peak-load pricing break down. For example, less capacity types will be employed. Either a system with partially dispatchable technologies only, or a system dominated by non-dispatchable technologies and supplemented by highly-dispatchables occurs. Non- and highly dispatchable technologies can be substitutes or complements. The probability of outage does not rise if non-dispatchable capacity becomes cheaper. In a system with non-dispatchables, capacity decisions cannot be decentralized by conventional markets because cost recovery is not possible. Thus, the integration of renewable electricity generators requires alternative market designs. [ABSTRACT FROM AUTHOR]

Capacity auctions with reliability options are seen as a promising possibility to reduce the investment risk for electricity generators as well as to set incentives for sufficient investments in generating capacity. However, there has been little attention so far on the interaction between a capacity market and an increasing share of renewable energy. In a first step we formalize the functioning of capacity auctions with reliability options. We improve their incentive regulation to allow effective incentives for sufficient investments. In a second step we study, with comparative statics, how an increasing share of renewable energy, varying carbon emission costs and the existing capacity mix influence the outcome of a capacity auction. For an increasing share of renewable energy, capacity auctions direct investments to more flexible power plants. This opposes the merit order effect of renewable energy which is observed at energy-only markets. A capacity market can therefore prevent missing flexibility feared at energy-only markets as a result of an increasing share of renewable energy. [ABSTRACT FROM AUTHOR]

This paper examines the incentives for efficient pricing mechanism in markets with non-convexities. The wholesale electricity market is a prominent example. Ideally, an efficient pricing mechanism produces market signals that reflect costs and scarcities, incents price-taking behavior and yields sufficient revenues to attract new investment. However, under non-convex conditions, there is no assurance that these goals can be fully achieved, and market equilibrium may not even exist. Previous studies on markets with convexities have been focusing on the revenue sufficiency problem. Positive results on incentives are relatively scarce. This paper is intended to fill the gap. With non-convexities, quasi-equilibrium entails solving separately a non-convex allocation model and a convexified pricing model with solution support payments in settlement. We consider three convex relaxation methods, including Lagrangian dualization, convex-hull relaxation and integer relaxation (Integer relaxation refers to a convex relaxation of mixed integer programing problem in which the integer variables are linearized). We show that quasi-equilibrium pricing is dominant strategy incentive compatible in the limit and the total side payment divided by the total surplus approaches zero when the market size (e.g., measured by the number of consumers) increases to infinity. In essence, the quasi-equilibrium pricing mechanism extends efficient pricing principles from a convex market environment to one that is non-convex in ways that preserve economic efficiency, incentive compatibility and revenue sufficiency. These results are illustrated in the context of wholesale electricity markets. Since 2014, price formation issues have been vigorously debated in the U.S. including FERC's conferences and proceedings with comments from academics, policy and business communities across ISO/RTO regions. Convex-hull pricing is generally considered an ideal solution but it remains computationally prohibitive. In this paper, we identify conditions under which the integer relaxation method can produce close and sometimes even exact approximations to convex-hull pricing. In April 2019, FERC authorized the use of integer relaxation as a just and reasonable pricing method for fast-start units in PJM's energy markets. [ABSTRACT FROM AUTHOR]

The literature on incentive-based regulation in the electricity sector indicates that the size of this sector in a country constrains the choice of frontier methods as well as the model specification itself to measure economic efficiency of regulated firms. The aim of this study is to propose a stochastic frontier approach with maximum entropy estimation, which is designed to extract information from limited and noisy data with minimal statements on the data generation process. Stochastic frontier analysis with generalized maximum entropy and data envelopment analysis—the latter one has been widely used by national regulators—are applied to a cross-section data on thirteen European electricity distribution companies. Technical efficiency scores and rankings of the distribution companies generated by both approaches are sensitive to model specification. Nevertheless, the stochastic frontier analysis with generalized maximum entropy results indicate that technical efficiency scores have similar distributional properties and these scores as well as the rankings of the companies are not very sensitive to the prior information. In general, the same electricity distribution companies are found to be in the highest and lowest efficient groups, reflecting weak sensitivity to the prior information considered in the estimation procedure. [ABSTRACT FROM AUTHOR]

In 1999 the GB retail energy market was open to competition for residential customers. In 2008 Ofgem began a series of regulatory interventions, notably a nondiscrimination condition and subsequently a restriction to four "simple tariffs". This reversed its previous policy of minimal intervention. This paper explores the reasons for this change of policy, drawing upon the responses of economists and others to Ofgem and Competition and Market Authority (CMA) consultations. It argues that key factors were a significant increase in energy prices before 2008, the reduced involvement of economists in senior roles at Ofgem, and systematic changes in Government policy and the statutory regulatory framework. Finally, the paper examines what the CMA Energy Market Investigation had to say about this in 2016. The CMA found that these were inappropriate regulatory interventions, and laid part of the blame on arrangements for governance of the regulatory framework. [ABSTRACT FROM AUTHOR]

We examine the role of information transparency in Alberta’s wholesale electricity market. Using data on firms’ bidding behavior, we analyze whether firms utilize information revealed in near real-time through the Historical Trading Report (HTR), which is released 10 min after each hour and contains a complete (de-identified) list of every firms’ bids into the wholesale market from the previous hour. We demonstrate that firms are often able to identify the offers of specific rivals by offer patterns adopted by those firms. For one of these firms, these patterns are associated with higher offer prices. This is consistent with allegations by Alberta’s Market Surveillance Administrator that firms may be utilizing unique bidding patterns to reveal their identities to their rivals to elevate market prices. We show that certain firms respond to rival offer changes with a lag consistent with responding to information revealed through the HTR, and that they respond differently to different firms, suggesting that they are able to infer identification. [ABSTRACT FROM AUTHOR]

Coincident peak pricing is used in several electricity markets to recover the embedded cost of infrastructure, such as transmission. In this approach, measured consumption at the time of the peak is used to set charges for that pricing period or a subsequent period. If transmission costs are truly sunk, then such a recovery is unlikely to be efficient. However, in the context of growing peak demand, new additions must be built. We consider the incentive properties of coincident peak pricing when related investments are not considered to be sunk, finding that it can reproduce the incentive properties of an ideal time-varying price. We also consider several variations on this assumption. [ABSTRACT FROM AUTHOR]

Prosumers are households that are both producers and consumers of electricity. A prosumer has a grid-connected decentralized production unit and makes two types of exchanges with the grid: energy imports when the local production is insufficient to match the local consumption and energy exports when local production exceeds it. There exists two systems to measure the exchanges: a net metering system that uses a single meter to measure the balance between exports and imports and a net purchasing system that uses two meters to measure separately power exports and imports. Both systems are currently used for residential consumption. We build a model to compare the two metering systems. Under net metering, the price of exports paid to prosumers is implicitly set at the price of the electricity that they import. We show that net metering leads to (1) too many prosumers, (2) a decrease in the bills of prosumers, compensated via a higher bill for traditional consumers, and (3) a lack of incentives to synchronize local production and consumption. [ABSTRACT FROM AUTHOR]

We analyze the design of policies to promote efficient distributed generation (DG) of electricity. The optimal policy varies with the set of instruments available to the regulator and with the prevailing DG production technology. DG capacity charges often play a valuable role in inducing optimal investment in DG capacity, allowing payments for DG production to induce the optimal production of electricity using non-intermittent DG technologies. Net metering can be optimal in certain settings, but often is not optimal, especially for non-intermittent DG technologies. [ABSTRACT FROM AUTHOR]

We analyze the effects of electricity market mergers in an environment where firms endogenously choose their level of forward contracts prior to competing in the wholesale market. We apply our model to Alberta's wholesale electricity market. Firms have an incentive to reduce their forward contract coverage in the more concentrated post-merger equilibrium. We demonstrate that endogenous forward contracting magnifies the price increasing impacts of mergers, resulting in larger reductions in consumer surplus. Current market screening procedures used to analyze electricity mergers consider firms' pre-existing forward commitments. We illustrate that ignoring the endogenous nature of firms' forward commitments can yield biased conclusions regarding the impacts of market structure changes such as mergers. In particular, we show that the price effects of mergers can be largely underestimated when forward contract quantities are held at pre-merger levels. Whether the profits of the merged firm are greater with fixed or endogenous forward quantities is ambiguous. [ABSTRACT FROM AUTHOR]

The creation of adequate investment incentives has been of great concern in the restructuring of the electricity sector. However, to achieve this, regulators have applied different market designs across countries and regions. In this paper we employ laboratory methods to explore the relationship between market design, capacity provision and pricing in electricity markets. Subjects act as firms, choosing their generation capacity and competing in uniform price auction markets. We compare three regulatory designs: (1) a baseline price cap system that restricts scarcity rents, (2) a price spike regime that effectively lifts these restrictions, and (3) a capacity market that directly rewards the provision of capacity. Restricting price spikes leads to underinvestment. In line with the regulatory intention both alternative designs lead to sufficient investment albeit at the cost of higher energy prices during peak periods and substantial capacity payments in the capacity market regime. To some extent these results confirm theoretical expectations. However, we also find lower than predicted spot market prices as sellers compete relatively intensely in capacities and prices, and the capacity markets are less competitive than predicted. [ABSTRACT FROM AUTHOR]

The paper is focused on modelling and analyzing the influence of different regulatory models on the level of quality of supply in electricity distribution, as measured by the duration of interruptions. The paper offers a description of the main features of the models and of the variables that influence service quality, and estimates their effect using a balanced panel data for 9 European Countries. We observe that when companies increase their remuneration by 1%, the duration of interruptions falls by approximately 1%. Regarding the regulatory models, price-cap, revenue-cap and cost plus are seen as the most efficient models for increasing the quality of service (given other resources such as revenues and incentives). The paper controls the differences between performances in the selected Countries and shows that the United Kingdom, Italy, Spain and Austria are the most efficient countries. Additionally, the paper concludes that incentives have a significant effect on quality. [ABSTRACT FROM AUTHOR]

Power pools constitute a set of sometimes complex institutional arrangements for efficiency-enhancing coordination among power systems. In many developing countries, where such institutional arrangements can't be established over the short term, there still can be scope for voluntary electricity-sharing agreements among power systems. Using a particular type of efficient risk-sharing model with no commitment we demonstrate that second-best coordination improvements can be achieved with low to moderate risks of participants leaving the agreement. In the absence of an impartial market operator who can observe production fluctuations in connected power systems, establishing quasi-markets for trading excess electricity helps to achieve some cooperation in mutually beneficial electricity sharing. [ABSTRACT FROM AUTHOR]

In Germany, substantial drops in wholesale power prices have become a regular phenomenon. While such price drops have far-reaching implications for the functioning of the power market, their underlying determinants remain poorly understood. To fill this gap, we propose a Markov regime-switching model to investigate low-price events at the European Power Exchange. Our analysis focuses on the role of energy policies that promote renewable energies and have led to significant reductions of nuclear capacities after the Fukushima accident. We find that high electricity infeed from renewable sources increases negative price spike probabilities, while the decommissioning of nuclear plants under the Nuclear Moratorium had an opposing effect. Simulations of market outcomes under different energy policies indicate that reaching ambitious renewable energy targets increases the frequency of low-price events and compromises the financial viability of conventional generation units, while a nuclear phase-out or an increase in storage capacities mitigates these effects. [ABSTRACT FROM AUTHOR]

We characterize the optimal regulatory policy to promote efficient demand response (DR) in the electricity sector. DR arises when consumers reduce their purchases of electricity below historic levels at times when the utility's marginal cost of supplying electricity is relatively high. The US Federal Energy Regulatory Commission (FERC) advocates compensation for DR that reflects the utility's marginal cost. We show that the optimal policy often provides less generous compensation, and demonstrate that implementation of the FERC's policy can reduce welfare well below the level secured by the optimal DR policy. [ABSTRACT FROM AUTHOR]

Price cap regulation (PCR) has experienced widespread adoption in the U.S. telecommunications industry, but not in the electricity sector. We suggest that these disparate experiences may reflect in part the manner in which PCR often is implemented in the U.S., relatively limited opportunity for 'regulatory bargains' in the electricity sector, and relatively limited competition in the transmission and distribution components of this sector. [ABSTRACT FROM AUTHOR]

This paper investigates the relationship between output-based incentives for service quality and the use of capital and non-capital resources to meet regulatory targets in the electricity industry. To conduct the empirical analysis we use a dataset collected with the support of the Italian energy regulatory authority, comprising micro data on monetary incentives and physical assets for the largest electricity distribution operator in Italy (86 % of the market). Our results show that physical assets and operational expenditures do affect service quality. Moreover, when we investigate causality in the relationship between incentives to quality and the use of capital and non-capital resources, we find that incentives Granger-cause capital expenditures (and not vice-versa). Finally, our results reveal an asymmetric effect of rewards and penalties on capital expenditures' decisions across areas with different quality levels. From these findings, we derive several policy implications. [ABSTRACT FROM AUTHOR]

The California Independent System Operator (CAISO) has implemented Convergence Bidding (CB) on February 1, 2011 under Federal Energy Regulatory Commission's September 21, 2006 Market Redesign and Technology Upgrade Order. CB is a financial mechanism that allows market participants, including electricity suppliers, consumers and virtual traders, to arbitrage price differences between the day-ahead (DA) market and the real-time (RT) market without physically consuming or producing energy. In this paper, market efficiency is defined in terms of trading profitability, where a zero-profit competitive equilibrium implies market efficiency (Jensen in, J Financial Econ 6(2):95-101, ). We analyze market data in the CAISO electric power markets, and empirically test for market efficiency by assessing the performance of trading strategies from the perspective of virtual traders. By viewing DA-RT spreads as payoffs from a basket of correlated assets, we can formulate a chance constrained portfolio selection problem, where the chance constraint takes two different forms as a value-at-risk constraint and a conditional value-at-risk constraint, to find the optimal trading strategy. A hidden Markov model (HMM) is further proposed to capture the presence of the time-varying forward premium. This is meant to be a contribution to the modeling of regime shifts in the electricity forward premium with unobservable states. Our backtesting results cast doubt on the efficiency of the CAISO electric power markets, as the trading strategy generates consistent profits after the introduction of CB, even in the presence of transaction costs. Nevertheless, by comparing with the performance before the introduction of CB, we find that the profitability decreases significantly, which enables us to identify the efficiency gain brought about by CB. Convincing evidence for the improvement of market efficiency in the presence of CB is further provided by the test for the Bessembinder and Lemmon (J Finance 57(3):1347-1382, ) model. [ABSTRACT FROM AUTHOR]

This paper investigates the incentives market participants have in the German electricity balancing mechanism. Strategic over and undersupply positions are the result of existing stochastic arbitrage opportunities between the spot market and the balancing mechanism. Clear indications for strategic behavior can be observed in aggregate market data. These structural imbalances increase the need for reserve capacity, raise system security concerns, and therefore place significant costs on consumers. The underlying problem is the disconnect between spot market, reserve capacity market and balancing mechanism. Alternative market design options discussed in this paper suggest better alignment between these markets/mechanisms. [ABSTRACT FROM AUTHOR]

Adequate extension of electricity transmission networks is required for integrating fluctuating renewable energy sources, such as wind power, into electricity systems. We study the performance of different regulatory approaches for network expansion in the context of realistic demand patterns and fluctuating wind power. In particular, we are interested in the relative performance of a combined merchant-regulatory price-cap mechanism compared to a cost-based and a non-regulated approach. We include both an hourly time resolution and fluctuating wind power. This substantially increases the real-world applicability of results compared to previous analyses. We show that a combined merchant-regulatory regulation, which draws upon a cap over the two-part tariff of the transmission company, leads to welfare outcomes superior to the other modeled alternatives. This result proves to be robust over a range of different cases, including such with large amounts of fluctuating wind power. We also evaluate the outcomes of our detailed model using the extension plans resulting from a simplified model based on average levels of load and wind power. We show that this distorts the relative performance of the different regulatory approaches. [ABSTRACT FROM AUTHOR]

This paper analyses how short-term operational efficiency and the $$\hbox {CO}_{2}$$ emissions of a power system depend on different subsidies for wind power and on the flexibility of the power system. This is analysed in the framework of a numerical power market model, calibrated to Danish data, where the start-up costs and other constraints in fossil-fuelled power plants are taken into account. The main conclusion is that flexibility is crucial for the costs of integrating wind power in an existing system. If thermal power plants are inflexible, subsidies for wind power should strive to increase the flexibility of the market by passing market signals to wind power. A subsidy that conceals market signals from wind power producers (a production subsidy) or disconnects wind power incentives from the market signals altogether (a fixed price) increases costs considerably. An inflexible power system should aim to introduce optimal subsidies (an investment subsidy) instead of production subsidies or a fixed price. The design of the subsidy scheme should take into account both the characteristics of the existing system and the characteristics of renewables. [ABSTRACT FROM AUTHOR]

We analyze the treatment and impact of idiosyncratic or firm-specific risk in regulation. Regulatory authorities regularly ignore firm-specific characteristics, such as size or asset ages, implying different risk exposure in incentive regulation. In contrast, it is common to apply only a single benchmark, the weighted average cost of capital, uniformly to all firms. This will lead to implicit discrimination. We combine models of firm-specific risk, liquidity management and regulatory rate setting to investigate impacts on capital costs. We focus on the example of the impact of component failures for electricity network operators. In a simulation model for Germany, we find that capital costs increase by $$\sim $$ 0.2 to 3.0 % points depending on the size of the firm (in the range of 3-40 % of total cost of capital). Regulation of monopolistic bottlenecks should take these risks into account to avoid implicit discrimination. [ABSTRACT FROM AUTHOR]

We find an asymmetric pass-through of European emission allowance (EUA) prices to wholesale electricity prices in Germany and show that this asymmetry disappeared in response to a report on investigations by the competition authority. The asymmetric pricing pattern, however, was not detected at the time of the report, nor had it been part of the investigations. Our results therefore provide evidence for the deterring effect of regulatory monitoring on firms which exhibit non-competitive pricing behavior. We do not find any asymmetric pass-through of EUA prices in recent years. Several robustness checks support our results. [ABSTRACT FROM AUTHOR]

Regression analysis suggests that zonal averages of locational marginal prices under the nodal market are about 2 % lower than the balancing energy prices that would occur under the previous zonal market structure in ERCOT. The estimates for the nodal market price effects are found after controlling for such factors as natural gas prices, total system load levels, non-dispatchable generation levels, the treatment of local congestion costs, and the treatment of the revenues received by the market from the auctioning of transmission rights. Our finding is limited to periods which are not characterized by price spikes in the wholesale market. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

By exercising market power, a firm will distort the production, and therefore the emissions decisions, of all firms in the market. This paper examines how the welfare implications of strategic behavior depend on how pollution is regulated. Under an emissions tax, aggregate emissions do not affect the marginal cost of polluting. In contrast, the price of tradable permits is endogenous. I show when this feedback effect increases strategic firms' output. Relative to a tax, tradable permits may improve welfare in a market with imperfect competition. As an application, I model strategic and competitive behavior of wholesalers in a Mid-Atlantic electricity market. Simulations suggest that exercising market power decreased emissions locally, thereby substantially reducing the regional tradable permit price. Furthermore, I find that had regulators opted to use a tax instead of permits, the deadweight loss from imperfect competition would have been even greater. [ABSTRACT FROM AUTHOR]

Renewable portfolio standards (RPSs) are popular market-based mechanisms for promoting development of renewable power generation. However, they are usually implemented without considering the capabilities and cost of transmission infrastructure. We use single- and multi-stage planning approaches to find cost-effective transmission and generation investments to meet single and multi-year RPS goals, respectively. Using a six-node network and assuming a linearized DC power flow, we examine how the lumpy nature of network reinforcements and Kirchhoff's Voltage Law can affect the performance of RPSs. First, we show how simplified planning approaches that ignore transmission constraints, transmission lumpiness, or Kirchhoff's voltage law yield distorted estimates of the type and location of infrastructure, as well as inaccurate compliance costs to meet the renewable goals. Second, we illustrate how lumpy transmission investments and Kirchhoff's voltage law result in compliance costs that are nonconvex with respect to the RPS targets, in the sense that the marginal costs of meeting the RPS may decrease rather than increase as the target is raised. Thus, the value of renewable energy certificates (RECs) also depends on the network topology, as does the amount of noncompliance with the RPS, if noncompliance is penalized but not prohibited. Finally, we use a multi-stage planning model to determine the optimal generation and transmission infrastructure for RPS designs that set multiyear goals. We find that the optimal infrastructure to meet RPS policies that are enforced year-by-year differ from the optimal infrastructure if banking and borrowing is allowed in the REC market. [ABSTRACT FROM AUTHOR]

In December 2010, France approved the law “Nouvelle Organisation du Marché de l’Electricité” (or NOME law) to promote competition in the retail electricity market. In practice, the law allows retailers to buy nuclear production from the incumbent, at a regulated access price. This mechanism works up to a ceiling of 100 terawatt hours, which represents one quarter of the incumbent’s production from nuclear plants. Each retailer is assigned a share of that amount proportionally to its portfolio of clients. We contribute to the debate raised by the NOME law regarding the evolution of retail market prices. We show that a price decrease results if the ceiling is sufficiently high compared to the market share of the retailers competing with the incumbent. This pro-competitive effect is stronger when the incumbent’s rivals take into account the impact of their market strategy on the redistribution rule. Finally, we find that, if the regulated price of the NOME electricity is set above the nuclear cost, the incumbent realizes a gain that may result in strategic withholding, weakening the pro-competitive effects of the law. [ABSTRACT FROM AUTHOR]

In 1996, the Federal Energy Regulatory Commission (FERC) sought to “remove impediments to competition in the wholesale bulk power marketplace and to bring more efficient, lower cost power to the Nation’s electricity consumers” through a series of market rules. A product of these rules was the establishment of regional transmission organizations (RTOs) and independent system operators (ISOs) charged with facilitating equal access to the transmission grid for electricity suppliers. Whether these changes in market structure have succeeded in achieving FERC’s goal to provide “lower cost power to the Nation’s electricity consumers” remains an open question. This paper utilizes a panel data set of the 48 contiguous United States and a treatment effects model in first differences to determine whether there have been changes in delivered electric prices as a result of the establishment of ISOs and RTOs. To avoid the confounding effects of electric restructuring, the model is estimated with the full panel data set, and then again without the states that have restructured their electric markets. This estimation shows that electricity prices fall approximately 4.8 % in the first 2 years of an ISO’s operation and that this result is statistically significant. However, this result is dependent on the presence of states that restructured their electricity markets. When these restructured states are removed from the data set the price effects of RTOs become indistinguishable from zero. The paper concludes that rate agreements are the principal source of the observed decrease in prices and that RTOs have not had the desired effect on electricity prices. [ABSTRACT FROM AUTHOR]

Economists acknowledge the problems of regulated transmission but have different views on the likely efficiency of merchant transmission. This paper first examines the evidence on alleged market failure and regulatory failure as experienced in practice in Australia, where there have been both regulated and merchant interconnectors. Merchant transmission has generally not exhibited the standard examples of market failure but regulated transmission generally has exhibited the standard examples of regulatory failure. Imperfect information-more specifically, in the form of lack of coordination-has often been a challenge whatever the approach. Experience in Argentina suggests that transactions costs are not a barrier to negotiation and efficient investment determined by users. Policy should seek to improve the regulatory framework and to remove barriers to private initiatives. An important role for regulation is to facilitate coordination between potential providers and users of transmission lines. [ABSTRACT FROM AUTHOR]

Although there are mechanisms to control market power in the spot market, withholding investments can still increase profits and 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 peak 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 cases 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, there can be no characterization in more complicated models that contain the market structures included here, and regulators or competition authorities cannot rely on contracts to induce sufficient capacity expansion by reducing market power. 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 an adequate incentive to invest in the presence of market power. [ABSTRACT FROM AUTHOR]

Using a generalized McFadden specification, we estimate the determinants of hourly response for the years 2006 through 2010 for all 16 standard retail customers who were on an optional real-time electricity rate offered by Duke Energy as of 2010, and provide a method to estimate how these customers would respond to time-of-use (TOU) and flat rates. We generalize the model to allow for inter-day response, as well as threshold prices, above which individual customer response may increase or decrease. With these inclusions, we find hourly elasticity for the group of customers to be as large as −0.7, larger than previous studies. We apply the method to examine a recent finding that time-differentiated rates could increase electric utility emissions. However, that result did not differentiate between real-time and TOU rates, and furthermore held energy use constant in comparing flat rates and time-differentiated rates. We perform a case study to examine emissions of SO, NOx, Hg, and CO based on predicted energy use changes as well as for an energy-neutral case for real-time, TOU and flat rates. Employing energy use predictions from the model, increased energy use results in increased emissions in almost all cases. For the energy-neutral case, time-differentiated rates increase CO as compared to flat rates, and the TOU rate causes a larger increase than does real-time pricing. But both rates decrease other emissions in the majority of years, particularly SO In addition, time-differentiated rates reduce NOx potency by shifting it to non-daylight hours when conditions for the formation of smog are less favorable. Our application leads to the conclusion that the effect of the rates on emissions must consider total energy use as well as the shift from peak to off-peak. Furthermore, the predictions require consideration of the generating mix at a more detailed level than was contained in previous studies. [ABSTRACT FROM AUTHOR]

Increasing electric power production from renewable energy sources is currently one of the major objectives of energy policy. The intermittent nature of renewables, such as wind and solar, necessarily imposes complex trade-offs for regulatory objectives, such as resource adequacy (and system reliability) versus reductions in green house gas emissions. We develop a highly stylized model of investments in order to derive insights regarding the workings of regulatory incentives for increased renewable energy. We first show that incentives are indeed needed when there are significant economies of scale in the form of 'learning by doing' or alternatively, when there is excess capacity in conventional technology due to legacy investments. We analyze two different regulatory schemes (feed-in tariffs and renewable portafolio standards) aimed at increasing investment in renewable capacity. We show that neither scheme is capable of inducing the socially optimal level of investment in renewable capacity. A single feed-in tariff fails to induce optimal investment as a feed-in tariff exceeding marginal costs of conventional technology incentivizes over-development of the most attractive sites which preempts investment in less attractive, yet socially valuable sites. A renewable portfolio standard that promotes increased investment in renewable technology induces under-investment in the conventional technology. These results suggest that a 'clinical' regulatory design, that is, one that promotes the right amount of renewable capacity without affecting conventional capacity is a challenging proposition. [ABSTRACT FROM AUTHOR]

Greenhouse gas regulation aimed at limiting the carbon emissions from the electric power industry will affect system operations and market outcomes. The impact and the efficacy of the regulatory policy depend on interactions of demand elasticity, transmission network, market structure, and strategic behavior of generators. This paper develops an equilibrium model of an oligopoly electricity market in conjunction with a cap-and-trade policy to study such interactions. We study their potential impacts on market and environmental outcomes which are demonstrated through a small network test case and a reduced WECC 225-bus model with a detailed representation of the California market. The results show that market structure and congestion can have a significant impact on the market performance and the environmental outcomes of the regulation while the interactions of such factors can lead to unintended consequences. [ABSTRACT FROM AUTHOR]

The regulatory process for setting public utilities' allowed rate of return on common equity has generally used the Gordon DCF, CAPM and Risk Premium specifications to estimate the cost of common equity. Despite the widely known problems with these models, there has been little movement to adopt more recently developed asset pricing models to provide additional evidence for estimating the cost of capital. This paper presents, validates empirically and applies a general yet simple consumption-based asset pricing specification to model the risk-return relationship for stocks and estimate the cost of common equity for public utilities. The model is not necessarily superior to other models in its practical results, yet these results do indicate that it should be used to provide additional estimates of the cost of common equity. Additionally, the model raises doubts as to whether assets such as utility stocks are a consumption (business cycle) hedge. [ABSTRACT FROM AUTHOR]

Traditionally, transmission assets for bulk power flow in the electric grid have been modeled as fixed assets in the short run, except during times of forced outages or maintenance. This traditional view does not permit reconfiguration of the transmission grid by the system operators to improve system performance and economic efficiency. The current push to create a smarter grid has brought to the forefront the possibility of co-optimizing generation along with the network topology by incorporating the control of transmission assets within the economic dispatch formulations. Unfortunately, even though such co-optimization improves the social welfare, it may be incompatible with prevailing market design practices since it can create winners and losers among market participants and it has unpredictable distributional consequences in the energy market and in the financial transmission rights (FTR) market. In this paper, we first provide an overview of recent research on optimal transmission switching, which demonstrates the substantial economic benefit that is possible even while satisfying standard N−1 reliability requirements. We then discuss various market implications resulting from co-optimizing the network topology with generation and we examine how transmission switching may affect locational Marginal Prices (LMPs), i.e., energy prices, and revenue adequacy in the FTR market when FTR settlements are financed by congestion revenues. [ABSTRACT FROM AUTHOR]

The Baltimore Gas and Electric Company (BGE) undertook a dynamic pricing experiment to test customer price responsiveness to different dynamic pricing options. The pilot ran during the summers of 2008 and 2009 and was called the Smart Energy Pricing (SEP) Pilot. In 2008, it tested two types of dynamic pricing tariffs: critical peak pricing (CPP) and peak time rebate (PTR) tariffs. About a thousand customers were randomly placed on these tariffs and some of them were paired with one of two enabling technologies, a device known as the Energy Orb and a switch for cycling central air conditioners. The usage of a randomly chosen control group of customers was also monitored during the same time period. In 2009, BGE repeated the pilot program with the same customers who participated in the 2008 pilot, but this time it only tested the PTR tariff. In this paper, we estimate a constant elasticity of substitution (CES) model on the SEP pilot's hourly consumption, pricing and weather data. We derive substitution and daily price elasticities and predictive equations for estimating the magnitude of demand response under a variety of dynamic prices. We also test for the persistence of impacts across the two summers. In addition, we report average peak demand reduction for each of the treatment cells in the SEP pilot and compare the findings with those reported from earlier pilots. These results show conclusively that it is possible to incentivize customers to reduce their peak period loads using price signals. More importantly, these reductions do not wear off when the pricing plans are implemented over two consecutive summers. Our analyses reveal that SEP participants reduced their peak usages in the range of 18 to 33% in the first summer of the SEP pilot and continued these reductions in the second summer. [ABSTRACT FROM AUTHOR]