Electricity

Electricity market design (without abstracts)

“Resilient Electricity Requires Consumer Engagement” (with Emmanuele Bobbio, Simon Brandkamp, Stephanie Chan, David Malec, and Lucy Yu) Working Paper, University of Maryland, August 2023.

“Price Responsive Demand in Britain’s Electricity Market” (with Emmanuele Bobbio, Simon Brandkamp, Stephanie Chan, David Malec, and Lucy Yu) Working Paper, University of Cologne, November 2021. [Medium blog]

“Electricity Markets in Transition: A multi-decade micro-model of entry and exit in advanced wholesale markets” (with Emmanuele Bobbio, David Malec, and Pat Sujarittanonta) Working Paper, University of Cologne, September 2021. [1-hour talk at Texas PUC, 15-minute INFORMS talk, 40-minute SynErgie talk+panel, Presentation]

“Fostering Resiliency with Good Market Design: Lessons from Texas,” Working Paper, University of Cologne, January 2022. [Presentation; Abridged version in Utility Dive, 23 March 2021; Public Radio segments (NPR = National, TPR = Texas): 3-minute overview on NPR, 24 Feb 2021; 17-minute interview on TRP, 1 Mar 2021; 59-minute “Failure of Power” on TPR, 3 Mar 2021; 5-minute competition issues on TPR, 10 Mar 2021; 8-minute climate change on TPR, 17 Mar 2021; 6-minute Buffett emergency reserve on TPR, 16 Apr 2021; proposed legislation, Inside Climate News, 17 Apr 2021; interview, Spark Spread, 16 April 2021; new ERCOT CEO on TPR, 27 Apr 2021; governance, Texas Tribune, 3 May 2021; 90-minute lessons learned, NECA webinar, 12 May 2021, summary of webinar, RTO Insider, 14 May 2021; on legislation to harm renewables, Utility Dive, 17 May 2021; 98-minute EWI seminar, 18 May 2021; shutoff moratorium, TPR, 21 May 2021; 32-minute talk Stony Brook Game Theory, 5 July 2021; 5-minute segment ABC 13 News, 3 Feb 2022; 3-minute follow-up ABC 13 News, 4 Feb 2022; Crossroads 24-minute podcast, 9 February 2022; TWS Game Changer 36-minute podcast, 15 March 2022 ]

“The Future of Power Markets,” Energy Unplugged by Aurora, episode 68, Peter Cramton interviewed by John Feddersen, 14 October 2021.

“A Forward Energy Market for a Reliable Grid,” Working Paper, University of Cologne, June 2021. [Only an abstract is available at the moment…]

“The Financial Impact of the 2021 Texas Winter Storm on Generation Owners: Outages, Forward Obligations, and Repricing” (with Emmanuele Bobbio, David Malec, and Pat Sujarittanonta) Working Paper, University of Cologne, May 2021. [Tableau workbook 386 MB; Tableau Reader to view the workbook]

“Hitting the Jackpot at Texans’ Expense,” Dallas Morning News, 8a, 6 Apr 2021. [8-minute segment repricing and reforms on TPR, 6 Apr 2021]

“Commentary: My monthly electric bill in Texas would be $250. In California, it is $1,000. Here’s why.” San Diego Union-Tribune, 1 September 2020. [Print edition]

“Local Flexibility Market,” Working Paper, University of Cologne, September 2019.

“Electricity Market Design,” Oxford Review of Economic Policy, 33:4, 589–612, November 2017. [Keynote Toulouse 2019, Presentation]

“Capacity Market Fundamentals” (with Axel Ockenfels and Steven Stoft), Economics of Energy & Environmental Policy, 2:2, September 2013. [Presentation]

“Economics and Design of Capacity Markets for the Power Sector” (with Axel Ockenfels), Zeitschrift für Energiewirtschaft, 36:113-134, 2012.

“Ökonomik und Design von Kapazitätsmärkten im Stromsektor” (with Axel Ockenfels), Energiewirtschaftliche Tagesfragen, 61:9, 14-15, 2011.

Wind Energy in Colombia: A Framework for Market Entry (with Walter Vergara, Alejandro Deeb, Natsuko Toba, and Irene Leino) The World Bank, Washington, DC, July 2010.

“Using Forward Markets to Improve Electricity Market Design” (with Lawrence M. Ausubel), Utilities Policy, 18, 195-200, 2010.

“Virtual Power Plant Auctions” (with Lawrence M. Ausubel), Utilities Policy, 18, 201-208, 2010.

“Prediction Markets to Forecast Electricity Demand” (with Luciano I. de Castro), Working Paper, University of Maryland, August 2009.

“Auctioning Long-term Gas Contracts in Colombia,” Working Paper, University of Maryland, September 2008. [Presentation]

“Forward Reliability Markets: Less Risk, Less Market Power, More Efficiency” (with Steven Stoft) Utilities Policy, 16, 194-201, 2008.

“Colombia’s Forward Energy Market,” Working Paper, University of Maryland, August 2007. [Presentation, Letter to NordPool]

“Product Design for Colombia’s Regulated Market,” Working Paper, University of Maryland, June 2007. [Presentation]

“Colombia Firm Energy Market,” (with Steven Stoft), Proceedings of the Hawaii International Conference on System Sciences, January 2007.

“Simulation of the Colombian Firm Energy Market,” (with Steven Stoft and Jeffrey West), Working Paper, University of Maryland, December 2006.

“Why We Need to Stick with Uniform-Price Auctions in Electricity Markets,” (with Steven Stoft), Electricity Journal, 20:1, 26-37, 2007.

“The Convergence of Market Designs for Adequate Generating Capacity,” (with Steven Stoft), White Paper, California Electricity Oversight Board, April 2006.

“New England’s Forward Capacity Auction,” University of Maryland, June 2006.

“A Capacity Market that Makes Sense,” (with Steven Stoft) Electricity Journal, 18, 43-54, August/September 2005. [Presentation]

“Review of the Proposed Reserve Markets in New England,” (with Hung-po Chao and Robert Wilson) White Paper, Market Design Inc., January 2005.

“Competitive Bidding Behavior in Uniform-Price Auction Markets,” Proceedings of the Hawaii International Conference on System Sciences, January 2004.

“Competitive Bidding Behavior in Uniform-Price Auction Markets,” Report before the Federal Energy Regulatory Commission, March 2003.

“Rebuttal Addendum: Assessment of Submissions of the California Parties,” Report before the Federal Energy Regulatory Commission, March 2003.

“Electricity Market Design: The Good, the Bad, and the Ugly,” Proceedings of the Hawaii International Conference on System Sciences, January, 2003.

“Pricing in the California Power Exchange Electricity Market: Should California Switch from Uniform Pricing to Pay-as-Bid Pricing?” (with Alfred E. Kahn, Robert H. Porter, and Richard D. Tabors), Blue Ribbon Panel Report, California Power Exchange, January 2001.

“Uniform Pricing or Pay-as-Bid Pricing: A Dilemma for California and Beyond,” (with Alfred E. Kahn, Robert H. Porter, and Richard D. Tabors), Electricity Journal, 70-79, July 2001.

“Eliminating the Flaws in New England’s Reserve Markets,” (with Jeffrey Lien) Working Paper, University of Maryland, March 2000. [Presentation]

“Review of the Reserves and Operable Capability Markets: New England’s Experience in the First Four Months,” White Paper, Market Design Inc., November 1999. [Figures and Tables | Presentation]

“The Role of the ISO in U.S. Electricity Markets: A Review of Restructuring in California and PJM,” (with Lisa Cameron) Electricity Journal, 71-81, April 1999.

“A Review of ISO New England’s Proposed Market Rules,” (with Robert Wilson) White Paper, Market Design Inc., September 1998. [Presentation]

“Auction Design for Standard Offer Service,” (with Andrew Parece and Robert Wilson) Working Paper, University of Maryland, July 1997. [Auction Rules]

“Using Auctions to Divest Generation Assets,” (with Lisa J. Cameron and Robert Wilson) Electricity Journal, 10:10, 22-31, December 1997.

Electricity market design (with abstracts)

“Price Responsive Demand in Great Britain’s Electricity Market” (with Emmanuele Bobbio, Simon Brandkamp, Stephanie Chan, David Malec, and Lucy Yu) Working Paper, University of Cologne, November 2021. [Medium blog]

Electricity markets balance supply and demand with price. Historically, this price response has come almost entirely from supply. However, when much of supply is intermittent or inflexible, price responsive demand becomes essential for reliability and resiliency. We measure how responsive consumers are to price in Great Britain from July 2020 to July 2021 with half-hourly individual-household data. Our sample includes customers with a dynamic rate that tracks wholesale cost, as well as flat-rate customers used to control for weather and other factors. A one percent increase in price reduces demand by 0.26 percent. This elasticity is larger for consumers owning low-carbon technologies. This price response is sufficient to maintain system balance in extreme events even when most consumers are unresponsive. Regulators can encourage price responsive demand through retail choice and subsidize enabling technologies. Regulators can protect consumers with mandated hedging in dynamic plans. Low-income households benefit most from such policies.

“Resilient Electricity Requires Consumer Engagement” (with Emmanuele Bobbio, Simon Brandkamp, Stephanie Chan, David Malec, and Lucy Yu) Working Paper, University of Cologne, November 2021.

“Lessons from the 2021 Texas Electricity Crisis,” Working Paper, University of Cologne, September 2021. [Presentation; Abridged version in Utility Dive, 23 March 2021; Public Radio segments (NPR = National, TPR = Texas): 3-minute overview on NPR, 24 Feb 2021; 17-minute interview on TRP, 1 Mar 2021; 59-minute “Failure of Power” on TPR, 3 Mar 2021; 5-minute competition issues on TPR, 10 Mar 2021; 8-minute climate change on TPR, 17 Mar 2021; 6-minute Buffett emergency reserve on TPR, 16 Apr 2021; proposed legislation, Inside Climate News, 17 Apr 2021; interview, Spark Spread, 16 April 2021; new ERCOT CEO on TPR, 27 Apr 2021; governance, Texas Tribune, 3 May 2021; 90-minute lessons learned, NECA webinar, 12 May 2021, summary of webinar, RTO Insider, 14 May 2021; on legislation to harm renewables, Utility Dive, 17 May 2021; 98-minute EWI seminar, 18 May 2021; shutoff moratorium, TPR, 21 May 2021; 32-minute talk Stony Brook Game Theory, 5 July 2021]

In February 2021, winter storm Uri brought extreme cold to Texas for many days. The cold caused a spike in electricity and natural gas demand and simultaneously a sharp drop in supply. The electricity shortage caused 4.5 million Texans to lose power for multiple days. Many lost water service too. Storm damage was extensive, including many deaths. This paper examines what happened and offers solutions to improve the reliability and resilience of critical infrastructures. Improved communication before and during the storm would limit the damage. Natural gas market reforms would enhance the reliability of the gas supply, enabling more generators to produce power. Improved energy efficiency would limit the cold-induced demand spike. In addition to ongoing initiatives to integrate storage and distributed generation, the system operator should introduce a voluntary forward energy market that lets market participants better manage risk and plan resources to meet demand. Price-responsive demand should also be encouraged to limit demand surges in cold snaps.

“A Forward Energy Market for a Reliable Grid,” Working Paper, University of Cologne, June 2021.

Electricity markets use the real-time energy price to balance supply and demand. Frequent shocks to supply and demand imply that the real-time price must vary from -$100 to $9000 per megawatt-hour, although the price is often about $30. Market participants trade forward products to manage risk from the high price volatility in the real-time market. For example, demanders typically buy ahead a quantity roughly equal to their real-time consumption, and suppliers sell forward an amount about equal to their real-time production. This paper describes how the system operator can facilitate forward trading with a forward energy market. The products are financial derivatives of the real-time energy product. Monthly forward energy is traded up to 48 months ahead for every type (weekday, weekend) and hour of the day. Hourly forward energy is traded up to 24 × 7 = 168 hours ahead. These monthly and hourly products enable both sides of the market to establish forward positions consistent with their needs to manage risk better. Trade occurs without frictions with hourly clearing using the Budish-Cramton-Lee-Kyle-Malec flow trading methodology. Flow trading allows participants to adjust positions simply and efficiently over time as information changes. The approach identifies unique prices and quantities for each product that maximizes as-bid social welfare. The system operator performs the settlement and manages collateral requirements. There is transparency about price, quantity, and forward positions. The market can be voluntary in energy-only markets. Alternatively, the forward energy market can be mandatory—replacing the capacity market—with an increasing schedule of obligations as we get closer to real-time. The advantage of the forward energy market is it gives participants much greater flexibility in adjusting positions consistent with needs.

Extreme cold in February 2021 caused a four-day shortage of electricity in Texas. Over 4.5 million Texans were without power, many for multiple days. We examine the financial implications for generation owners. In aggregate, generators lost $9.2 billion, assuming forward obligations equal to 90% of winter storm capacity. Losses stemmed from failing to produce power sufficient to cover forward positions or generating power at a loss due to high natural gas prices. Both electricity and gas prices were more than one hundred times pre-storm prices. The Texas market rules include a circuit breaker intended to reduce the shortage price after two days. However, the circuit breaker, designed for summer shortages, failed to reduce the price of $9000 per megawatt-hour. Some have proposed repricing to limit the money at stake. Repricing would increase the aggregate loss by $2.5 billion, assuming 90% forward obligations. Market integrity would be harmed.

“Electricity Markets in Transition: A multi-decade micro-model of entry and exit in advanced wholesale markets” (with Emmanuele Bobbio, David Malec, and Pat Sujarittanonta) Working Paper, University of Cologne, February 2021. [1-hour talk at Texas PUC, 15-minute INFORMS talk, Presentation]

Electricity markets worldwide are undergoing a many-decade transition in the way electricity is generated and consumed. The success of this transition depends critically on climate policy and market design. We model the most advanced electricity markets in the world to evaluate the impact of alternative policies on electricity market outcomes over the next 40 years, including costs, profits, social welfare, risks, and reliability. Each year, investors decide which resources enter and exit given forward-looking consistent expectations about energy profits, prices, and costs. The model is unique in modeling investment decisions at the individual unit level based on precisely calculated profits from energy, reserve, and capacity markets. These profits depend critically on the resource structure, which changes each year with investor decisions. New and essential elements of electricity markets, such as battery storage and price responsive demand are fully modeled. The model provides detailed insights into how policies such as carbon pricing impact the transition to renewable energy.

“Commentary: My monthly electric bill in Texas would be $250. In California, it is $1,000. Here’s why.” San Diego Union-Tribune, 1 September 2020. [Print edition]

“Local Flexibility Market,” Working Paper, University of Cologne, September 2019.

A local flexibility market is presented that addresses intrazonal congestion in a zonal electricity market. The market lets system operators access flexibility at multiple voltage levels to satisfy transmission constraints. Market participants offer local flexibility intraday in a continuous trading process. This supply is matched with demand from system operators. The market-based redispatch is transparent and technology neutral. Inc-dec gaming is mitigated with features to detect and sanction the behavior. Cost-based redispatch from conventional generation serves as a backstop if additional flexibility is required close to real time. This further mitigates inc-dec gaming by disciplining behavior in the spot market. An advantage of the approach in Europe is that it represents a modest change from the current market and therefore can be implemented sooner and with less risk.

“Electricity Market Design,” Oxford Review of Economic Policy, 33:4, 589–612, November 2017. [Keynote Toulouse 2019, Presentation]

Electricity markets are designed to provide reliable electricity at least cost to consumers. This paper describes how the best designs satisfy the twin goals of short-run efficiency—making the best use of existing resources—and long-run efficiency—promoting efficient investment in new resources. The core elements are a day-ahead market for optimal scheduling of resources and a real-time market for security-constrained economic dispatch. Resources directly offer to produce per their underlying economics and then the system operator centrally optimizes all resources to maximize social welfare. Locational marginal prices, reflecting the marginal value of energy at each time and location, are used in settlement. This spot market provides the basis for forward contracting, which enables participants to manage risk and improves bidding incentives in the spot market. There are important differences in electricity markets around the world, reflecting different economic and political settings. Electricity markets are undergoing a transformation as the resource mix transitions from fossil fuels to renewables. The main renewables, wind and solar, are intermittent, have zero-marginal cost, and lack inertia. These challenges can be met with battery storage and improved demand response. However, good governance is needed to assure the market rules adapt to meet new challenges.

“Capacity Market Fundamentals” (with Axel Ockenfels and Steven Stoft), Economics of Energy & Environmental Policy, 2:2, September 2013. [Presentation]

Electricity capacity markets work in tandem with electricity energy markets to ensure that investors build adequate capacity, in line with consumer preferences for reliability. The need for a capacity market stems from several market failures. One particularly notorious problem of electricity markets is low demand flexibility. Most customers are unaware of the real time prices of electricity, have no reason to respond to them, or cannot respond quickly to them, leading to highly price-inelastic demand. This contributes to blackouts in times of scarcity and to the inability of the market to determine the market-clearing prices needed to attract an efficient level and mix of generation capacity. Moreover, the problems caused by this market failure can result in considerable price volatility and market power that would be insignificant if the demand-side of the market were fully functional. Capacity markets are a means to ensure resource adequacy while mitigating other problems due to the demand side flaws. Our paper describes the basic economics behind the adequacy problem and addresses important challenges and misunderstandings in the process of actually designing capacity markets.

“Economics and Design of Capacity Markets for the Power Sector” (with Axel Ockenfels), Zeitschrift für Energiewirtschaft, 36:113-134, 2012.

Capacity markets are a means to assure resource adequacy. The need for a capacity market stems from several market failures the most prominent of which is the absence of a robust demand-side. Limited demand response makes market clearing problematic in times of scarcity. We present the economic motivation for a capacity market, present one specific market design that utilizes the best design features from various resource adequacy approaches analyzed in the literature, and we discuss other instruments to deal with the problems. We then discuss the suitability of the market for Europe and Germany in particular.

“Ökonomik und Design von Kapazitätsmärkten im Stromsektor” (with Axel Ockenfels), Energiewirtschaftliche Tagesfragen, 61:9, 14-15, 2011.

Wind Energy in Colombia: A Framework for Market Entry (with Walter Vergara, Alejandro Deeb, Natsuko Toba, and Irene Leino) The World Bank, Washington, DC, July 2010.

The purpose of this report is to provide decision makers in Colombia (and by extension other countries or regions), who are considering the deployment or consolidation of wind power, with a set of options to promote its use. The options presented are the result of an analysis of the Colombian market; this analysis included simulations and modeling of the country’s power sector, and extensive consultations with operators, managers, and agents. More information on the analysis and simulations is presented in the appendixes. Wind was chosen to exemplify the range of renewable energy alternatives available to complement traditional power sector technologies on the basis of its technical maturity, its relatively low cost compared to other options, the country’s experience, and its wind power potential.

“Using Forward Markets to Improve Electricity Market Design” (with Lawrence M. Ausubel), Utilities Policy, 18, 195-200, 2010.

Forward markets, both medium term and long term, complement the spot market for wholesale electricity. The forward markets reduce risk, mitigate market power, and coordinate new investment. In the medium term, a forward energy market lets suppliers and demanders lock in energy prices and quantities for one to three years. In the long term, a forward reliability market assures adequate resources are available when they are needed most. The forward markets reduce risk for both sides of the market, since they reduce the quantity of energy that trades at the more volatile spot price. Spot market power is mitigated by putting suppliers and demanders in a more balanced position at the time of the spot market. The markets also reduce transaction costs and improve liquidity and transparency. Recent innovations to the Colombia market illustrate the basic elements of the forward markets and their beneficial role.

“Virtual Power Plant Auctions” (with Lawrence M. Ausubel), Utilities Policy, 18, 201-208, 2010.

Since their advent in 2001, virtual power plant (VPP) auctions have been widely implemented. In this paper, we describe the various design choices that virtually all VPP auctions have had in common and also discuss a few aspects of the auction design that have varied significantly among the VPP auctions to date. We then consider whether VPP auctions have been an effective tool for promoting the objectives of regulators. We find that VPP auctions are effective devices for facilitating new entry into electricity markets and for developing wholesale markets, while they are not particularly well suited to making large reductions in market power in the spot market.

“Prediction Markets to Forecast Electricity Demand” (with Luciano I. de Castro), Working Paper, University of Maryland, August 2009.

Forecasting electricity demand for future years is an essential step in resource planning. A common approach is for the system operator to predict future demand from the estimates of individual distribution companies. However, the predictions thus obtained may be of poor quality, since the reporting incentives are unclear. We propose a prediction market as a form of forecasting future demand for electricity. We describe how to implement a simple prediction market for continuous variables, using only contracts based on binary variables. We also discuss specific issues concerning the implementation of such a market.

“Auctioning Long-term Gas Contracts in Colombia,” Working Paper, University of Maryland, September 2008. [Presentation]

This paper presents an approach to auctioning long-term gas contracts in Colombia. I propose an annual auction for long-term firm gas contracts. The auction would assign and price all firm gas contracts, with the exception of gas from the Guajira field, which is assigned administratively at a regulated price. The proposal is a partial market design in that it does not address the transportation of gas from producer to consumer.

“Forward Reliability Markets: Less Risk, Less Market Power, More Efficiency” (with Steven Stoft) Utilities Policy, 16, 194-201, 2008.

A forward reliability market is presented. The market coordinates new entry through the forward procurement of reliability options—physical capacity bundled with a financial option to supply energy above a strike price. The market assures adequate generating resources and prices capacity from the bids of competitive new entry in an annual auction. Efficient performance incentives are maintained from a load-following obligation to supply energy above the strike price. The capacity payment fully hedges load from high spot prices, and reduces supplier risk as well. Market power is reduced in the spot market, since suppliers enter the spot market with a nearly balanced position in times of scarcity. Market power in the reliability market is addressed by not allowing existing supply to impact the capacity price. The approach, which has been adopted in New England and Colombia, is readily adapted to either a thermal or a hydro system.

“Colombia’s Forward Energy Market,” Working Paper, University of Maryland, August 2007. [Presentation, Letter to NordPool]

This paper presents a market design for Colombia’s forward energy market, which is scheduled to began in 2008. The forward energy market is an organized market to procure energy for electricity customers on a forward basis. It includes both the regulated market (residential and other small customers) and the nonregulated market (large customers). Currently, regulated customers represent 68% of the total electricity demand and nonregulated customers represent the remaining 32%. The proposed design is novel in that it integrates both the regulated and nonregulated customers into a single organized market. Although the regulated and nonregulated energy products remain distinct, their integration into a single market facilitates arbitrage between the products, improves liquidity, and reduces transaction costs. Both regulated and nonregulated customers benefit from this unified approach. This paper presents all elements of the market design: the product design (see also Cramton 2007), the auction design, and the transition to the new market.

“Product Design for Colombia’s Regulated Market,” Working Paper, University of Maryland, June 2007. [Presentation]

This paper presents a product design for Colombia’s regulated market (MOR), which is scheduled to begin in 2008. The regulated market consists of residential and other small customers. Currently, regulated customers represent 69% of the total load. I propose a market based on a single load-following product in which each supplier bids to serve its desired share of the Colombia regulated load. Thus, a supplier that wins a 10% share at auction has an obligation to serve 10% of the actual regulated load in every hour of the commitment period. The supplier is paid the MOR clearing price for every MWh of energy supplied. Deviations between the supplier’s hourly supply and obligation are settled at the spot energy price or the scarcity price, whichever is lower. The spot settlement price is capped at the scarcity price, since the firm energy market provides price coverage for prices above the scarcity price (about US$125/MWh). One-hundred percent of regulated load is purchased on behalf of the regulated customers in a sequence of auctions. Thus, MOR together with the firm energy market provides 100% price coverage for all regulated customers. MOR provides price coverage from zero to the scarcity price, and the firm energy market provides price coverage above the scarcity price. This accomplishes two things: 1) it provides rate stability for regulated customers, and 2) it provides revenue stability for suppliers. The result is reduced risk for both sides of the market.

“Colombia Firm Energy Market,” (with Steven Stoft), Proceedings of the Hawaii International Conference on System Sciences, January 2007.

A firm energy market for Colombia is presented. Firm energy—the ability to provide energy in a dry period—is the product needed for reliability in Colombia’s hydro-dominated electricity market. The firm energy market coordinates investment in new resources to assure that sufficient firm energy is available in dry periods. Load procures in an annual auction enough firm energy to cover its needs. The firm energy product includes both a financial call option and the physical capability to supply firm energy. The call option protects load from high spot prices and improves the performance of the spot market during scarcity. The market provides strong performance incentives through the spot energy price. Market power is addressed directly: existing resources cannot impact the firm energy price. Since load is hedged from high spot prices, the market can rely on high prices to balance supply and demand during dry periods, rather than rationing.

“Simulation of the Colombian Firm Energy Market,” (with Steven Stoft and Jeffrey West), Working Paper, University of Maryland, December 2006.

We present a simulation analysis of the proposed Colombian firm energy market. The main purpose of the simulation is to assess the risk to suppliers of participation in the market. We also are able to consider variations in the market design, and assess the impact of alternative auction parameters. Three simulation models are developed and analyzed. The first model (Model 1) uses historical price data from October 1995 through May 2006 to assess the performance risk of hypothetical thermal and hydro generating units. The second model (Model 2) uses historical price and operating data to assess performance risk of the actual generating units in Colombia over the same period. This analysis allows us to assess company risk. The third genericclomid model (Model 3) differs from the other models in that it explicitly models the firm energy auction and investments going forward. Thus, the model is able to assess how the distribution of firm energy purchases differs from the firm energy target, and how this distribution depends on the firm energy demand curve. Model 3 also studies the investment decisions of suppliers, the impact of lumpy investments, and the impact of a higher scarcity price. Taken together, the simulation results demonstrate the risk reducing benefits of the firm energy market. Provided there is competitive new entry in response to load growth, the firm energy market should work well at coordinating investment in new supply, while minimizing supplier and consumer risks.

“Why We Need to Stick with Uniform-Price Auctions in Electricity Markets,” (with Steven Stoft), Electricity Journal, 20:1, 26-37, 2007.

Wholesale electricity markets are commonly organized around a spot energy market. Buyers and suppliers submit bids and offers for each hour and the market is cleared at the price that balances supply and demand. Buyers with bids above the clearing price pay that price, and suppliers with offers below the clearing price are paid that same price. This uniform-price auction, which occurs both daily and throughout the day, is complemented by forward energy markets. In practice, between 80 and 95 percent of wholesale electricity is traded in forward energy markets, often a month, or a year, and sometimes many years ahead of the spot market. However, because forward prices reflect spot prices, in the long run, the spot market determines the total cost of energy. It also plays a critical role in the least-cost scheduling and dispatch of resources, and provides an essential price signal both for short-run performance and long-run investment incentives. Arguments that the uniform-price auction yields electricity prices that are systematically too high are incorrect. However, insufficiently hedged spot prices will result in energy costs that fluctuate above and below the long-run average more than regulated prices and more than is socially optimal. Tampering with the spot price would cause inefficiency and raise long-term costs. The proper way to dampen the impact of spot price fluctuations is with long-term hedging. Although re-regulation can provide a hedge, there are less costly approaches.

“The Convergence of Market Designs for Adequate Generating Capacity,” (with Steven Stoft), White Paper, California Electricity Oversight Board, April 2006.

This paper compares market designs intended to solve the resource adequacy (RA) problem, and finds that, in spite of rivalrous claims, the most advanced designs have nearly converged. The original dichotomy between approaches based on long-term energy contracts and those based on short-term capacity markets spawned two design tracks. Long-term contracts led to call-option obligations which provide market-power control and the ability to strengthen performance incentives, but this approach fails to replace the missing money at the root of the adequacy problem. Hogan’s energy-only market fills this gap. On the other track, the short-term capacity markets (ICAP) spawned long-term capacity market designs. In 2004, ISO New England proposed a short-term market with hedged performance incentives essentially based on high spot prices. In 2005 we developed for New England a forward capacity market with load obligated to purchase a target level of capacity covered by an energy call option. The two tracks have now converged on two conclusions: (1) High real-time energy prices should provide performance incentives. (2) High energy prices should be hedged with call options. We argue that two more conclusions are needed: (3) Capacity targets rather than high and volatile spot prices should guide investment, and (4) long-term physically based options should be purchased in a forward market for capacity. The result will be that adequacy is maintained, performance incentives are restored, market power and risks are reduced from present levels, and prices are hedged down to a level below the present price cap.

“New England’s Forward Capacity Auction,” University of Maryland, June 2006.

This note provides a brief description of New England’s Forward Capacity Auction (FCA) for the procurement of electricity capacity. The description is based on the 6 March 2006 Settlement Agreement. The description here presents a simpler description of the auction mechanics, and limits the presentation to the key elements relevant to someone providing software and other support to implement the primary auction. In addition, some motivation for the approach is given. The description here is not a software specification, but rather a high-level description of the auction. Many implementation details are yet to be resolved. These details will be resolved in the Market Rule for the Forward Capacity Market.

“A Capacity Market that Makes Sense,” (with Steven Stoft) Electricity Journal, 18, 43-54, August/September 2005. [Presentation]

We argue that a capacity market is needed in most restructured electricity markets, and present a design that avoids problems found in the early capacity markets. The proposed market only rewards capacity that contributes to reliability as demonstrated by its performance during hours in which there is a shortage of operating reserves. The capacity price responds to market conditions, increasing when and where capacity is scarce and decreasing to zero when and where it is sufficiently plentiful. Market power in the capacity market is addressed by basing the capacity price on actual capacity, rather than bid capacity, so generators cannot increase the capacity price by withholding supply. Actual peak energy rents (the short-run energy and reserve profits of a benchmark peaking unit) are subtracted from the capacity price. This allows the capacity market to more accurately control short-run profits and suppresses market power in the energy market. This design both avoids and hedges energy market risk, and by suppressing market power avoids regulatory risk. Risk reduction saves consumers money as do the performance and investment incentives inherent in the pay-for-performance mechanism.

“Review of the Proposed Reserve Markets in New England,” (with Hung-po Chao and Robert Wilson) White Paper, Market Design Inc., January 2005.

ISO New England proposes reserve markets designed to improve the existing forward reserve market and improve pricing during real-time reserve shortages. We support all of the main elements of the proposal. For example, we agree that little is gained by allowing reserve availability bids in the day-ahead market. Doing so greatly increases the complexity of the market without the prospect of more efficient pricing. Rather, offline reserves are most efficiently priced and awarded well in advance, as is done by the improved forward reserve market.

“Competitive Bidding Behavior in Uniform-Price Auction Markets,” Proceedings of the Hawaii International Conference on System Sciences, January 2004.

Profit-maximizing bidding in uniform price auction markets involves bidding above marginal cost. It therefore is not surprising that such behavior is observed in electricity markets. This incentive to bid above marginal cost is not the result of coordinated action among the bidders. Rather, each bidder is independently selecting its bid to maximize profits based on its estimate of the residual demand curve it faces. The supplier bids a price for its energy capacity to optimize its marginal tradeoff between higher prices and lower quantities. Price response from either demand or other suppliers prevents the supplier from raising its bid too much. Profit maximizing bidding should be expected and encouraged by regulators. It is precisely this profit maximizing behavior that guides the market toward long-run efficient outcomes.

“Competitive Bidding Behavior in Uniform-Price Auction Markets,” Report before the Federal Energy Regulatory Commission, March 2003.

Profit-maximizing bidding in uniform price auction markets involves bidding above marginal cost. It therefore is not surprising that such behavior is observed in electricity markets. Common bidding behavior such as “hockey stick” bids easily are explained by suppliers determining their supply offers to maximize profits. This incentive to bid above marginal cost is not the result of coordinated action among the bidders. Rather, each bidder is independently selecting its bid to maximize profits based on its estimate of the residual demand curve it faces. Profit-maximizing bidding does not mean that “the sky’s the limit.” Typically, bidders are limited in how high they want to bid. As prices increase, operators become increasingly concerned that their capacity will not be selected—that someone else will step in front of them in the merit order. Only when (1) demand does not respond to price, and (2) the largest unhedged block of capacity is essential to meet demand can the bidder holding this largest block profitably name any price. In all other cases, the supplier bids a price for its energy capacity to optimize its marginal tradeoff between higher prices and lower quantities. Price response from either demand or other suppliers prevents the supplier from raising its bid too much. Profit maximizing bidding should be expected and encouraged by regulators. It is precisely this profit maximizing behavior that guides the market toward long-run efficient outcomes.

“Rebuttal Addendum: Assessment of Submissions of the California Parties,” Report before the Federal Energy Regulatory Commission, March 2003.

“Electricity Market Design: The Good, the Bad, and the Ugly,” Proceedings of the Hawaii International Conference on System Sciences, January, 2003.

This paper examines principles of market design as applied to electricity markets. I illustrate the principles with examples of both good and bad designs. I discuss one of the main design challenges—dealing with market power. I then discuss FERC’s choice of a standard market design.

“Uniform Pricing or Pay-as-Bid Pricing: A Dilemma for California and Beyond,” (with Alfred E. Kahn, Robert H. Porter, and Richard D. Tabors), Electricity Journal, 70-79, July 2001.

Any belief that a shift from uniform to as-bid pricing would provide power purchasers substantial relief from soaring prices is simply mistaken. The immediate consequence of its introduction would be a radical change in bidding behavior that would introduce new inefficiencies, weaken competition in new generation, and impede expansion of capacity.

“Eliminating the Flaws in New England’s Reserve Markets,” (with Jeffrey Lien) Working Paper, University of Maryland, March 2000. [Presentation]

“Review of the Reserves and Operable Capability Markets: New England’s Experience in the First Four Months,” White Paper, Market Design Inc., November 1999. [Figures and Tables | Presentation]

I review the performance of the operating reserves and the operable capability markets in New England. The review covers the first four months of operation from May 1 to August 31, 1999. The review is based on my knowledge of the market rules and their implementation by the ISO, and the market data during this period, including bidding, operating, and settlement information. In the review, I (1) identify the potential market flaws with these markets, (2) look at the performance of the markets to see if the potential problems have materialized, (3) evaluate the ISO’s short-term remedies for these market flaws, and (4) propose alternative medium-term solutions to the identified problems. I find that the OpCap and reserve markets have serious flaws that must be addressed. The ISO’s short-term fixes have been necessary and effective at addressing the immediate problems. However, better solutions can be adopted in the medium term. In particular, I recommend (1) eliminate the OpCap market, (2) establish a downward sloping demand curve for reserves, (3) pay the clearing price to all resources that provide the service, (4) establish the true real-time supply curve as simply the quantity of the resource made available in real time, (5) establish back down bids in the TMSR market (bids would be infrequent, perhaps monthly), (6) never set a price in the TMSR market less than the largest lost opportunity cost, (7) continue to cascade the quantities of the bids between operating reserve products, and (8) correct the classification of off-line units that provide a service that looks and acts like TMSR. All of these changes are consistent with the long-term solutions proposed for NEPOOL. These changes represent an important step toward the long-term solution involving multi-settlement energy and reserve markets. These markets should be designed carefully to address the basic economic and engineering issues necessary for an efficient wholesale electricity market.

“The Role of the ISO in U.S. Electricity Markets: A Review of Restructuring in California and PJM,” (with Lisa Cameron) Electricity Journal, 71-81, April 1999.

Several regions of the U.S. have sought to restructure the electric power industry by separating the potentially competitive generation sector from the natural monopoly functions of electricity transmission and distribution. Under this restructuring scheme, a central authority, which we will refer to as the independent system operator (ISO), is given control over both the transmission system and the spot market for electricity. The ISO’s role in managing the spot market is relatively uncontroversial. This is because the spot market takes place in real time and requires continuous physical adjustments to electricity supply and demand subject to complex constraints, such as the need to maintain voltage and frequency within tight bands. Although the ISO’s role in managing the spot market is generally accepted, its role in scheduling and pricing generators prior to actual dispatch was hotly debated during the development of California’s market and remains a contentious issue. Like other restructured electricity markets, the California market requires generators to be scheduled for operation on a day-ahead basis and allows for adjustments in these day-ahead schedules up to an hour ahead of actual dispatch. However, the California ISO has a minimal role in this scheduling process; almost all scheduling is carried out by a number of competing scheduling coordinators, referred to as SCs. In contrast, the ISO in the Pennsylvania New Jersey Maryland market (PJM) schedules all generators that do not elect to schedule themselves. This paper discusses the California and PJM approaches to shed light on the controversy over the ISO’s role in pre-dispatch phases of the market. Section I describes the California market while Section II briefly reviews PJM. Section III outlines the costs and benefits associated with limiting the ISO’s role in the scheduling phases of the market. Section IV summarizes recent experience in California and PJM and offers conclusions.

“A Review of ISO New England’s Proposed Market Rules,” (with Robert Wilson) White Paper, Market Design Inc., September 1998. [Presentation]

This report reviews the proposed rules for restructured wholesale electricity markets in New England. We review the market rules, both individually and collectively, and identify potential problems that might limit the efficiency of these markets. We examine alternatives and identify the key tradeoffs among alternative designs. We believe that the wholesale electricity market in New England can begin on December 1, 1998. However, improvements are needed for long-run success. We have identified four major recommendations:

Switch to a multi-settlement system.
Introduce demand-side bidding.
Adopt location-based transmission congestion pricing, especially for the import/export interfaces.
Fix the pricing of the ten minute spinning reserves.

“Auction Design for Standard Offer Service,” (with Andrew Parece and Robert Wilson) Working Paper, University of Maryland, July 1997. [Auction Rules]

During the transition to a competitive electricity market, when a consumer does not select an electricity provider, who provides service to the customer and at what price? An auction for this “standard offer service” is a market-based way to assign the service responsibility and to determine its price. We explore the design issues in establishing rules for such an auction.

“Using Auctions to Divest Generation Assets,” (with Lisa J. Cameron and Robert Wilson) Electricity Journal, 10:10, 22-31, December 1997.

In most states, ratepayers will compensate utilities for their stranded costs. As a result, these costs must be measured as accurately as possible, in a manner that is easily understood by all concerned parties. We describe the options for measuring stranded costs and argue that a simultaneous ascending auction is the best approach.

Electricity

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