Comparison of Market Designs

Transcription

1 Public Utility Commission of Texas Comparison of Market Designs Market Oversight Division Report Project 26376, Rulemaking Proceeding on Wholesale Market Design Issues in the Electric Reliability Council of Texas Principal Author: Sam Zhou, Ph.D. Other Contributors: Tony Grasso Grace Niu Editors: David Hurlbut, Ph.D. Richard Greffe Team Leader: Eric S. Schubert, Ph.D. Market Oversight Division Public Utility Commission of Texas January 7, 2003

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3 Acknowledgement As one of its main responsibilities, the Market Oversight Division feels that it is important to monitor market operations and continue to improve market design and operating rules in order to establish a successful and workably competitive electricity market in Texas. Helping market participants to better understand the operation of competitive electricity markets, which are designed differently and have different degree of emphasis on the importance of various market elements, can be very beneficial in making a final decision about the future of market design in the Electric Reliability Council of Texas. In particular, such an understanding can highlight various trade offs and reasons beyond the decisions made by other markets to select a particular path among existing potential options. The Market Oversight Division Staff has prepared this Study Report to facilitate the Commission discussion in this rulemaking proceeding, which will eventually lead to the establishment of a successful competitive electricity market. Staff believes that the information provided in this Study Report, addressing the fundamentals and presenting some measures of actual performance by various competitive electricity markets across the world, will provide a solid ground for detailed discussions that will follow in the near future. I would like to take this opportunity to show appreciation for tireless efforts by Dr. Sam Zhou to complete this comprehensive Study Report in a relatively short period of time. In addition, I appreciate hard work by other team members, Tony Grasso and Grace Niu, who helped to prepare some of the information used in this Study Report. Special thanks go to Dr. David Hurlbut, Richard Greffe, and Dr. Eric Schubert for their excellent review, comments, and editing to finalize this Study Report. Parviz M. Adib, Ph.D. Director of Market Oversight Division

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5 Comparison of Market Designs Market Oversight Division Report Contents Introduction...1 I. FERC Standard Market Design...3 Detailed Requirements in FERC s SMD...4 Suggested Benchmark Matrix of Market Implementation...6 II. Existing Markets and Planned Market Designs PJM Interconnection Market New York Independent System Operator Market ISO New England Market Electric Reliability Council of Texas Market Northeast Regional Transmission Organization California Independent System Operator Market Midwest Independent System Operator Market Ontario Independent Electricity Market Operator Market Power Pool of Alberta Market New Electricity Trading Arrangements Market of England and Wales Nordic Power Exchange Market National Electricity Market of Australia New Zealand Electricity Market...71 III. Preliminary Summary...76 Preliminary Conclusions A Mandatory Centralized Dispatch Pool Market Invites Gaming Opportunities LMP Complicates Locational Market Power Spot Energy Markets With Centralized Unit Commitment Can Be Problematic...77 Energy Trading Results...78 Average Energy Comparison Between PJM, NYISO, and ISO-NE...79 Ancillary Services Prices of Various Markets...81 Regulation Reserve Services Price...82 Spinning Reserve Service Prices...83 Non Spinning Reserve Prices...85 Uplift and Congestion Costs of the U.S. Markets...88 Market Power Mitigation: Other Alternatives of Automated Mitigation Plan...89 IV. Options for ERCOT Market Design...90 Day-Ahead Market as a Spot Energy Market...92 Congestion Management...93 Some Possible Options for ERCOT Market Design...93 Appendix I: Summary of Market Design Appendix II: LMP Security-Constrained Dispatch Process Appendix III: ERCOT Two-Step Dispatch Process Appendix IV: Automated Ex Ante Market Power Mitigation Measure...104

6 List of Figures Figure 1: FERC SMD...5 Figure 2: Timeline and Bilateral Schedule of Major Deregulated Markets...8 Figure 3: PJM Model...10 Figure 4: NYISO Model...18 Figure 5: ISO-NE Model...28 Figure 6: ERCOT Model...35 Figure 7: NERTO SMD 2.X Model...42 Figure 8: CAISO MD02 Model...45 Figure 9: MISO Model...48 Figure 10: Ontario IMO Model...50 Figure 11: Power Pool of Alberta Model...53 Figure 12: England and Wales NETA Model...55 Figure 13: NORD Pool Model...61 Figure 14: Australia NEM...66 Figure 15: NZEM...72 Figure 16: Problem of Centralized Dispatch...77 Figure 17: Monthly Average Energy Price Comparison...80 Figure 18: Energy Price Duration Curves for ISO-NE, PJM and NYISO, May 2001 April Figure 19: Weighted Average Regulation Prices...82 Figure 20: Average Regulation Prices...83 Figure 21: Weighted Average Spinning Reserve Prices...84 Figure 22: Average Spinning Reserve Prices...85 Figure 23: Weighted Average Non-Spinning Reserve Prices...86 Figure 24: Average Non-Spinning Reserve Prices...87 Figure 25: Energy Market Functions...91 Figure 26: Option Figure 27: Option Figure 28: Option Figure 29: Option Figure 30: LMP Dispatch Process Figure 31: ERCOT Two-Step Dispatch Process Figure 32: Zonal-ERCOT-Nodal Mitigation Measure...105

7 List of Tables Table 1: PJM Hourly Energy HHIs...14 Table 2: PJM Installed Capacity HHIs...14 Table 3: PJM Load-Weighted Average LMP ($/MWh)...14 Table 4: NYISO Unweighted Ancillary Services Prices...23 Table 5: Broad Indicators, , , Table 6: All-In Price of Wholesale Power (Load Weighted)...31 Table 7: Ancillary Services Prices of NEISO (Aug. 01 Aug. 02)...32 Table 8: HHIs for ERCOT Zones...38 Table 9: Annual Weighted Average Prices for Balancing Energy...38 Table 10: Average Ancillary Services Prices in ERCOT...39 Table 11: Installed Generating Capacity in Nord Pool...60 Table 12: Energy Trading in Various Markets...79 Table 13: Energy Market Clearing Prices of ERCOT, ISO-NE, NYISO, and PJM...79 Table 14: Ancillary Services Market Components...81 Table 15: Weighted Average Regulation Price ($/MW)...82 Table 16: Average Regulation Services Prices ($/MW)...83 Table 17: Weighted Average Prices of Spinning Reserve ($/MW)...84 Table 18: Average Spinning Reserve Prices ($/MW)...85 Table 19: Weighted Average Non Spinning Reserve Prices ($/MW)...86 Table 20: Average Non Spinning Reserve Price ($/MW)...87 Table 21: Uplift of PJM, NYISO, ISO-NE, and ERCOT ($ Millions)...88 Table 22: Congestion Costs of the U.S. Markets (Millions)...88 Table 23: Trade-offs of Major Components of Market Design...92 Table 24: Available Options of Market Design...94 Table 25: Characteristic Comparison of Different Markets...95

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9 Introduction Electricity market deregulation has been underway for more than a decade since the United Kingdom opened a Power Pool in April Some markets such as Nord Pool and New Zealand have been very successful, but others such as California and the pre-neta UK market have failed. Therefore, as ERCOT reevaluates its current market design, it is important to consider the lessons learned from other markets. To that end, this report summarizes the energy markets, operational processes, and performance benchmarks of ten existing electricity markets and three proposed market designs as follows: Existing markets o Pennsylvania-New Jersey-Maryland Interconnect (PJM) o New York ISO (NYISO) o ISO-New England (NE-ISO) o Electric Reliability Council of Texas (ERCOT) o Independent Electricity Market Operator (IMO) of Ontario o Power Pool of Alberta o New Energy Trading Arrangement (NETA) of the United Kingdom o Nordic Power Exchange (Nord Pool) o National Electricity Market (NEM) of Australia o New Zealand Electricity Market (NZEM) Proposed markets o Northeast Regional Transmission Operator (NERTO) o California Market Design 2002 (MD02) o Mid-West ISO (MISO) Section I of this report describes the market design principles and required components of the Standard Market Design (SMD) proposed by the Federal Energy Regulatory Commission (FERC). A set of performance measures aligned to FERC s Strawman SMD Staff Discussion Paper on Market Metrics is identified to establish an objective benchmark when different markets are evaluated. With a brief introduction of each market, Section II of this report summarizes the market design of different markets, describes the important components in each market, and assesses their performance benchmarks. The benchmarks are primarily based on the respective 2001 annual reports of the Market Monitoring Units for the respective markets. One can see that each market has many good features, as well as some areas that could be improved such as high uplift, high congestion costs, and high price correction rates. An important observation is that ERCOT has the highest generation resource concentrations (HHI) in the United States and some similar features of market structure to the NETA of the United Kingdom. Section III of this report conducts a preliminary summary of various market models and compares the energy prices, ancillary service prices, congestion costs, and uplift of PJM, NYISO, ISO-NE, and ERCOT. One important observation is that the ancillary services in ERCOT market have higher prices for several ancillary services products. Even though ERCOT has a smaller percentage of balancing energy in the real-time market, it also has higher monthly load weighted average energy prices compared to other U.S. deregulated electricity markets. 1

10 Possible reasons are the inherent characteristics such as high concentration ratios in the ERCOT market. The design of a competitive wholesale market is determined by two fundamental principles: 1) competitive and efficient energy trading, and 2) reliable operation of the grid. From the summary of different market structures presented in this report, it is evident that there are significant differences in the design of energy trading and in the ways to conduct security constrained economic dispatch. Some markets have a day-ahead market for spot trading and some markets just have a day-ahead or an hour-ahead scheduling process to facilitate real time operation. Most overseas markets adopt a zonal model, but a majority of U.S. markets use a nodal model. If energy trading (primarily bilateral vs. day-ahead spot market) and congestion management (zonal vs. nodal) are the most important market design elements, it is possible to construct four options (combinations) for analysis. Section IV describes the market structures of the four options and identifies their unique characteristics. Several key questions that should be addressed in ERCOT market redesign are raised for further study and discussion. 2

11 I. FERC Standard Market Design The Federal Energy Regulatory Commission (FERC), in its Working Paper 1 on Standardized Transmission Service and Wholesale Electric Market Design, states that: 1. The objective of standard market design for wholesale electric markets is to establish a common market framework that promotes economic efficiency and lower delivered energy costs, maintains power system reliability, mitigates significant market power and increases the choices offered to wholesale market participants. All customers should benefit from an efficient competitive wholesale energy market, whether or not they are in states that have elected to adopt retail access. 2. Market rules and market operation must be fair, well defined and understandable to all market participants. 3. Imbalance markets and transmission systems must be operated by entities that are independent of the market participants they serve. 4. Energy and transmission markets must accommodate and expand customer choices. Buyers and sellers should have options which include self-supply, long-term and short-term energy and transmission acquisitions, financial hedging opportunities, and supply or demand options. 5. Market rules must be technology- and fuel-neutral. They must not unduly bias the choice between demand or supply sources nor provide competitive advantages or disadvantages to large or small demand or supply sources. Demand resources and intermittent supply resources should be able to participate fully in energy, ancillary services and capacity markets. 6. Standard market design should create price signals that reflect the time and locational value of electricity. The price signal here, created by LMP should encourage short-term efficiency in the provision of wholesale energy and long-term efficiency by locating generation, demand response and/or transmission at the proper locations and times. But while price signals should support efficient decisions about consumption and new investment, they are not full substitutes for a transmission planning and expansion process that identifies and causes the construction of needed transmission and generation facilities or demand response. 7. Demand response is essential in competitive markets to assure the efficient interaction of supply and demand, as a check on supplier and locational market power, and as an opportunity for choice by wholesale and end-use customers. 8. Transmission owners will continue to have the opportunity to recover the embedded and new costs of their transmission systems. Consistent with current policy, merchant transmission capacity would be built without regulatory assurance of cost recovery. 1 Federal Energy Regulatory Commission, Working Paper on Standardized Transmission Service and Wholesale Electric Market Design, May 2002, pp

12 9. Customers under existing contracts (real or implicit) should continue to receive the same level and quality of service under standard market design. However, transmission capacity not currently used and paid for by these customers must be made available to others. 10. Standard market design must not be static. It must not inhibit adaptation of the market design to regional requirements nor hinder innovation. Detailed Requirements in FERC s SMD Under the stated goal of Standardized Market Design (SMD), To enhance competition in wholesale electric markets and broaden the benefits and cost savings to all wholesale and retail customers, 2 the electricity wholesale market should meet the following requirements: Each Regional Transmission Operator (RTO) should develop a day-ahead energy market, a real-time spot energy market, a financial transmission rights market, and simultaneously allow for bilateral contracts. Market-clearing prices should be derived through bid-based, security-constrained dispatch and be linked to the physical dispatch of the system through locational marginal pricing. Each RTO should seek to implement an energy market that, to the extent feasible, imposes the least amount of additional cost to the public. Each RTO should develop transparent rules and procedures that integrate and coordinate system operation with market administration functions for energy, ancillary services, and congestion management. RTOs should acknowledge the role of state utility commissions and the regional reliability authority in ensuring long-term supply adequacy and should coordinate with these entities in implementing a market approach. Load-serving entities should ensure that sufficient operating reserves and capacity are committed to meet the adequacy obligation established by the regional reliability authority or state commissions. Each RTO, in coordination with transmission owners or Independent Transmission Coordinators (ITCs) within the RTO, should manage or coordinate the operation of the transmission system. Limits may be necessary on bidding flexibility to mitigate market power. For example, suppliers may be required to submit a start-up bid which would remain in place for a period of several months (rather than re-bid every day). As more demand response becomes available in a regional market, limits on supplier bidding flexibility can be relaxed. 2 Federal Energy Regulatory Commission, Working Paper on Standardized Transmission Service and Wholesale Electric Market Design, March 15, 2002, p. 1. 4

13 The demand side must be able to participate in the energy market. The demand side can participate as buyers or sellers (e.g., offering to sell operating reserves). As a buyer, an entity must be able to submit bids that indicate it is willing to vary the quantities it purchases based on the prices that it may be charged. The proposed SMD demonstrated in Figure 1 consists of: 1. Bilateral contract 2. Day-ahead and real time market 3. The day-ahead regulation and operating reserve markets (jointly optimize energy, regulation, operating reserves, and transmission service.) 4. Locational marginal pricing (LMP) 5. Congestion Revenue Rights (CRR) 6. Long-term resource adequacy requirement such as Installed Capacity Market (ICAP) 7. Demand-side responsiveness 8. Market power mitigation (Optional Automated Mitigation Procedure (AMP)) The transmission provider may identify generating units that must run for reliability. Because these units are required by reliability and security of grid operation and have locational market power, the bids submitted by these units should be subject to mitigation. Similarly, market power in load pockets must be mitigated with on-going behavioral mitigation, such as call options or bid caps, unless structural solutions are possible. Figure 1: FERC SMD Demand-side responsiveness CRR Auction Market Capacity Markets Market Based Bid curve $1000/MWh Bila teral cont ract Day-ahead market LMP & CRR value C A P AMP Real time A/S & Balancing market LMP & reliability 5

14 Suggested Benchmark Matrix of Market Implementation The SMD NOPR discusses some of the ways market monitors have measured the structure of their markets and the conduct of market participants, and it requests comment on how the market monitor should develop useful measures that permit interregional comparisons. A more detailed discussion was conducted at the FERC SMD Staff Conference on Market Monitoring which was held in October The FERC Staff prepared a strawman discussion paper 3 which identified the following categories to frame the discussion of specific metrics: General market functioning Assessment of market structure Assessment of market performance Evaluation of participant conduct According to the strawman, metrics concerning the state of the markets start with a general description of the market and changes over the year, emphasizing measures such as: Energy market prices Quantities delivered Ancillary services prices Transmission usage and pricing, and Market ratios, such as a ratio of spot and forward prices. Typical market structural indicators highlight the competitiveness and efficiency of the market in the defined relevant markets. Structural indices may be controversial, however measures such as Herfindahl-Hirschman Index (HHI) or a measure of pivotal supply can serve as indicators of the state of the market structure and, if properly standardized, permit comparisons across markets. Market performance measures typically focus on whether market outcomes are consistent with outcomes expected in a competitive market. Aggregate market performance measures should cover a wide range of markets (e.g., energy markets, ancillary services, and capacity revenue rights), periods (e.g., day ahead and real time markets, longer term), and conditions (e.g., prices in relation to costs, output in relation to capacity, market depth and liquidity). Since no single measure will satisfy all the purposes of performance measurement, a balanced group of measures will be needed. A Lerner index that indicates the price markup over cost could be used to assess the competitive level of a market. General measures may indicate a need for further investigation, but drawing a line between outcomes that are caused by difficult to measure fundamentals (such as scarcity) and difficult to measure undesirable behavior (such as economic withholding) remains a matter of analytic judgment. Mitigation tools that can be employed ex ante may be preferable to ex post monitoring, but metrics to monitor the behavior of individual participants will remain important. 3 Federal Energy Regulatory Commission, Strawman" Staff Discussion Paper on Market Metrics, SMD Staff Conference on Market Monitoring, Docket No. RM01-12, October 2,

15 The number of Automated Mitigation Procedure (AMP) events or investigations of market power abuse are good indications about market conduct. Based on the FERC strawman on market metrics, the following measures will be used in this paper for comparing the implementation of various markets: 1. Concentration ratio (HHI) Concentration ratios are a summary measure of market shares, a key element of market structure. The concentration ratio used here is the Herfindahl-Hirschman Index, which is calculated as the sum of the squares of the market shares of the firms in a market. According to FERC s Merger Policy Statement, a market can be broadly characterized as unconcentrated when the market HHI is below 1000 (the equivalent of 10 firms with equal market shares); as moderately concentrated when the market HHI is between 1000 and 1800; and as highly concentrated when the market HHI is greater than 1800 (the equivalent of between 5 and 6 firms with equal market shares). 2. Average energy price, or load-weighted average energy price adjusted by fuel cost and trend The overall level of prices is a good general indicator of market performance, although overall price results must be interpreted carefully because of the multiple factors that affect them. 3. Ancillary services prices and capacity prices 4. Net revenue (load paid price minus operating costs) Net revenue is an indicator of the profitability of an investment in generation. 5. Price-cost mark-up (Lerner index) and trend The price-cost markup is a widely used measure of market power. 6. Congestion costs, percentage and trend Congestion costs and trend is a combined measure for operation efficiency and market power mitigation. 7. Market power abuse investigation and mitigation A good market design could be immune from frequent market power abuse or prolonged high prices. 8. Operational Issues Operational issues such as noncompliance rate and price correction rate give a good indication about operating efficiency of a market. 9. Retail competition (switching rate) and load participation (energy) rate Reducing inelasticity of demand could help to mitigate market power. 10. New entry and capacity construction percentage High levels of new entry and capacity construction percentage signal a long-term competitive market. 7

16 II. Existing Markets and Planned Market Designs This study reviews the market design and 2001 performance of ten existing markets (PJM, NYISO, ISO-NE, ERCOT, IMO, Alberta, Nord Pool, NETA, NEM, and NZEM) and the market design of three proposed markets (NERTO, MISO, MDO2). The following chart summarizes the deregulation timeline and the major structural evolution of these markets: Figure 2: Timeline and Bilateral Schedule of Major Deregulated Markets Apr 1990: UK Pool opens Overseas Oct 1996: New Zealand NZEM Dec 1998: Australia NEM opens Mar 2001: NETA replaces UK Pool Jan. 1991: Norway launches Nordpool Jan. 1996: Sweden in Nordpool Jan. 1998: Finland in Nordpool Jan. 2000: Denmark in Nordpool North America Jan 1998: PJM ISO created Mar 1998: Cal ISO opens May 1999: ISO-NE opens Nov 1999: NY ISO launches July 2001: ERCOT opens Jan. 2001: Alberta Pool opens May 2002: Ontario IMO launches Physical Bilateral / Self- Schedule UK Pool Australia NE-ISO (40%Fin) CAISO 0 ~10% NYISO (50%) PJM (64%) Nord Pool (71%) NETA (98%) ERCOT (97%) 0 (Spot Market) Max ISO 25% 50% 75% Min ISO 100% Bilateral Contract Market deregulation started a decade ago with a central dispatched pool structure with competitive bids and offers. In such a market, suppliers would submit all of their generated electricity output with associated prices and all buyers would submit bids to buy electricity. The pool would be the only place to trade electric energy and settle the energy prices based on demand-supply movement. Hence, both suppliers and buyers would be limited in their ability to 8

17 hedge against potential risks. The pool structure can suffer from various forms of market power because 1) electricity demand is relatively inelastic and consumers as a whole have little influence on the prices, 2) a large amount of energy trading provides strong incentive for suppliers to raise prices by physical and economic withholding, and 3) market power can be exercised in various situations that are difficult to monitor and correct in a timely manner such as happened in the United Kingdom (pre-neta) and California. There is a trend in recent market designs to move away from the pool structure toward using bilateral contracts to mitigate market power and hedge risks. One major example of this is the UK s recent replacement of the pool model with the bilateral oriented NETA. An important lesson from the California crisis is the crucial role of managing risk through market design. In most other industries, risk bearing is spread along the supply chain via long-term forward contracts or financial instruments for hedging. This is generally accepted as the optimal behavior since a seller and a buyer have common interests in mutual insurance against the volatility of spot prices. Similarly, electricity markets have been successful everywhere that spot markets account for only a small fraction of transactions. 1. PJM Interconnection Market The Pennsylvania-New Jersey-Maryland (PJM) Interconnection serves about 9.6 million customers with installed capacity of 59,000 MW. 4 In the year 2000, PJM served 262,081 GWh of energy, which represents about 7% of U.S. electric energy. PJM s generation fleet has a fuel mix of 31% coal, 27% oil, 22% nuclear, 6% natural gas, and 5% hydroelectric. PJM uses the tight pool model rather than the power exchange model. PJM allows physical bilateral scheduling that enables it to leverage its long-standing pool and its emerging bilateral markets. PJM operates a day-ahead energy market, a real-time energy market, a daily capacity market, monthly and multi-monthly capacity markets, a regulation market, and the monthly Financial Transmission Rights (FTRs) auction market. PJM introduced nodal energy pricing with marketclearing prices in April 1998 and nodal market-clearing prices (see Appendix II) based on competitive offers in April PJM implemented a competitive auction-based FTR market in May Daily capacity markets were introduced in January 1999 and were broadened to include monthly and multi-monthly markets in mid PJM implemented the day-ahead energy market and the regulation market June PJM plans to add a spinning reserves market in the near future. PJM currently calculates and posts LMPs for more than 1,750 buses located in the PJM control area and an additional 600 buses located outside the PJM control area. LMPs are also calculated for aggregate load buses and the PJM eastern and western hubs. 4 Information in this section is based on (1) PJM Interconnection State of the Market Report 2001 by Market Monitoring Unit, PJM Interconnection, L.L.C. June 2001; and (2) The Amended and Restated Operating Agreement of the PJM Interconnection, L.L.C. ( Operating Agreement ) setting forth procedures for a twosettlement system; Filing to Federal Energy Regulatory Commission, March 10, The section also contains information from the PJM website: 9

18 Figure 3: PJM Model Monthly FTR Auction Market Load Participation Capacity Markets ICAP 18% Must offer Bilat eral contr act, 64% Day-ahead 15% energy market & Regulation market Real time 21% energy market LMP prices & FTR value LMP prices & Dispatch $100/MWh $1000/MWh c a P *The difference between PJM model and SMD is that PJM model lacks an Automated Mitigation Procedure (AMP). PJM s two-settlement system consists of two markets a day-ahead market and a real-time balancing market. Separate accounting settlements are performed for each market. For the year 2001, real-time spot market activity averaged 6,563 MW during peak periods and 6,395 MW during off-peak periods, or 21% of average loads. In the day-ahead market, spot market activity averaged 4,794 MW on-peak and 4,877 MW off-peak, or 15% of average loads. The day-ahead market is a financial market and thus may be used to provide a hedge against price fluctuations in the real-time spot market. Also, for any generator that is scheduled in the day-ahead market, the offer data submitted into the day-ahead market (before 12 noon) will automatically carry over into the real-time market. Day-ahead Market The day-ahead market is a forward market in which clearing prices are calculated for each hour of the next operating day based on generation offers, demand bids, bilateral transaction schedules, and incremental and decremental bids, which are purely financial bids to supply and demand energy in the day-ahead market. The day-ahead market uses exactly the same underlying model of the system as the real time market. PJM s day-ahead market enables market participants to purchase and sell energy at binding dayahead prices. It further permits customers to schedule bilateral transactions at binding day-ahead congestion charges based on the differences in the LMP between a transaction s source and sink locations. In the day-ahead market, Load Serve Entities (LSEs) will submit hourly demand schedules, including any price sensitive demand bids, for the amount of demand that they wish to lock-in at day-ahead prices. Generators that are designated as Capacity Resources 5 must submit 5 A Capacity Resource is the net capacity from owned or contracted for generating facilities which are accredited pursuant to the procedures set forth in the Reliability Assurance Agreement among Load Serving Entities in the PJM Control Area. 10

19 an offer schedule into the day-ahead market unless they are self-scheduled or unavailable due to outage. Non-capacity resources have the option to make offers into the day-ahead market, but are not required to do so. Transmission customers may submit fixed or dispatchable bilateral transaction schedules into the day-ahead market and may specify the maximum amount of congestion charges they are willing to pay between the transaction sources and sink if congestion occurs in the day-ahead schedule. FTRs are available to hedge congestion in the day-ahead market. Price sensitive demand bids are offered by entities with actual physical demand such as LSEs. These bids allow a customer to place a bid to purchase a certain quantity of energy at a certain location if the day-ahead price is at or below a certain price. Decremental bids are similar to price-sensitive demand bids. They allow a marketer or other similar entity without physical demand to place a bid to purchase a certain quantity of energy at a certain location if the day-ahead price is at or below a certain price. Incremental bids are essentially the flip side of decremental bids. The PJM day-ahead market allows all market participants to use incremental and decremental bidding as financial hedging tools to provide additional price certainty in a variety of situations. Up-to congestion bids permit transmission customers to specify how much they are willing to pay for congestion by bidding a certain maximum amount for congestion between the transaction source and sink. If the congestion charges are less than the amount specified in the bid, then the transaction will be reflected in the day-ahead schedule. The up-to bids protect transmission customers from paying uncertain congestion charges by guaranteeing that they will pay no more than the amount reflected in their bids. Transmission customers also may use an incremental and decremental bid pair to accomplish the same type of hedging strategy, which further enhances their price certainty options. All spot purchases and sales in the day-ahead market are settled at the day-ahead prices. PJM allows virtual bidding so market participants can submit bids that are purely financial in order to arbitrage between the day ahead and real time market prices. Such bids are treated in the unit commitment process as if they were physical. PJM calculates the day-ahead final schedule based on the bids, offers, and schedules submitted. Day-ahead bids are of three types: energy bids by generators that self-commit, virtual bids, and multidimensional bids including cost and operating parameters by generators that want to be committed by PJM s central unit commitment algorithm. Generators that are committed by PJM are made whole on a 24-hour basis (i.e., PJM guarantees cost recovery). All self-committed and centrally committed units are scheduled for each hour in the day-ahead market through a security constrained bid-based dispatch, and the corresponding hourly LMPs are calculated. The day-ahead scheduling process will incorporate PJM reliability requirements and reserve obligations into the analysis. The resulting hourly schedules and LMPs represent binding financial commitments to market participants. Real-time Market The real-time balancing market is based on actual real-time operations. As in the day-ahead market, generators that are Capacity Resources must participate in the real-time balancing market or may self-schedule. However, Capacity Resources that are available but were not selected in the day-ahead scheduling may alter their bids for use in the balancing market. If a generator chooses not to alter its bid, its original bid in the day-ahead market remains in effect. 11

20 The balancing market is the real-time energy market in which hourly clearing prices are determined by the actual bid-based, least-cost, security constrained unit commitment dispatch. LSEs will pay balancing prices (real-time LMP) for any demand that exceeds their day-ahead scheduled amounts but will receive revenue (real-time LMP) for demand deviations below their day-ahead scheduled amounts. Similarly, generators are paid balancing prices for any generation that exceeds their day-ahead scheduled amounts and will pay for any generation deficit below their day-ahead scheduled amounts. Transmission customers will pay congestion charges (or may receive congestion credits) for bilateral transaction quantity deviations from day-ahead schedules. Ancillary Services Market The PJM regulation market, introduced on June 1, 2000, supplanted an administrative and costbased regulation procurement mechanism that had been in place for many years. Market participants can now acquire regulation in the regulation market in addition to self-scheduling their own resources or purchasing regulation bilaterally. The market for regulation permits suppliers to make offers of regulation subject to a bid cap of $100 per MW, plus opportunity costs. Capacity Market An LSE has the obligation to own or acquire Capacity Resources greater than or equal to the peak load that it serves plus a reserve margin of about 18%. LSEs have the flexibility to acquire capacity in a variety of ways. Capacity can be obtained by building units, by entering into bilateral arrangements, or by participating in the capacity credit markets operated by PJM. Collectively, these arrangements are known as the Installed Capacity Market, or ICAP. The PJM capacity credit markets are intended to provide the mechanism to balance the supply of and demand for capacity not met via the bilateral market or via self-supply. Capacity credit markets were created to provide a transparent, market based mechanism for new, competitive LSEs to acquire the Capacity Resources needed to meet their capacity obligations and to sell Capacity Resources when no longer needed to serve load. PJM s daily capacity credit markets ensure that LSEs can match Capacity Resources with changing obligations caused by daily shifts in retail load. Monthly and multi-monthly capacity credit markets provide a mechanism that matches longer-term capacity obligations with available Capacity Resources. Financial Transmission Rights PJM introduced Financial Transmission Rights (FTRs) in its initial market design in order to provide a hedge against congestion for firm transmission service customers, who pay the costs of the transmission system. PJM introduced the monthly FTR auction market to provide increased access to FTRs and thus increased price certainty for transactions not otherwise hedged by allocated FTRs. In PJM, firm point-to-point (PTP) and network transmission service customers may request FTRs as a hedge against the congestion costs that can result from locational marginal pricing. An FTR is a financial instrument that entitles the holder to receive revenues (or charges) based on transmission congestion measured as the hourly energy locational marginal price differences in the day-ahead market across a specific path. Transmission customers are hedged against real-time congestion by matching real-time energy schedules with day-ahead energy schedules. FTRs can also provide a hedge for market participants against the basis risk 12

21 associated with delivering energy from one bus or aggregate to another. An FTR holder does not need to deliver energy in order to receive congestion credits. FTRs can be purchased with no intent to deliver power on a path. Price Cap PJM s mitigation consists of the $1,000/MWh bid cap in the PJM energy market and the $100/MW bid cap in the PJM regulation market. To mitigate local market power, PJM limits the offers of units which are dispatched out of merit order to relieve transmission constraints, to marginal cost plus 10%. PJM has a number of additional rules designed and implemented in order to limit market power. PJM is investigating other rules changes to reduce the incentives to exercise market power. PJM Market Monitoring Unit 2001 Market Report The Market Monitoring Unit (MMU) concludes that in 2001 the energy markets were reasonably competitive, the capacity markets experienced a significant market power issue in the beginning of the year, the regulation market was competitive, and the FTR auction market was competitive. The MMU concludes that the rule changes implemented by PJM addressed the immediate causes of market power in the capacity market, that the PJM capacity market was reasonably competitive later in 2001, but that market power remains a serious concern given the extreme inelasticity of demand and the high levels of concentration in the capacity credit markets. The MMU concludes that there are potential threats to competition in the energy, capacity and regulation markets that require ongoing scrutiny and in some cases may require action in order to maintain competition. Under certain conditions, market participants do possess some ability to exercise market power in PJM markets. Performance Benchmark of PJM Market Concentration ratio (HHI) The results of the aggregate PJM HHI calculations for both the installed and the hourly measure (Tables 1 and 2) indicate that the PJM energy market is, in general, moderately concentrated by the FERC standards. Hourly energy market HHIs were calculated based on the real-time energy output of generators located in the PJM control area, adjusted for hourly imports. The installed HHIs were calculated based on the installed capacity of PJM generating resources, adjusted for aggregate import capability. Overall market concentration varies from 975 to 2140 based on the hourly measure and from 1155 to 1405 based on the installed measure. 13

22 Table 1: PJM Hourly Energy HHIs Import level Overall Minimum Overall Maximum Maximum Average Minimum Table 2: PJM Installed Capacity HHIs Overall Minimum Overall Average Overall Maximum Overall Average energy price and fuel-adjusted load-weighted average energy price PJM load in 2001 was virtually identical to load in 2000 for slightly more than 90% of the hours. The simple hourly average system wide LMP was 15.1% higher in 2001 than in 2000 ($32.38/MWh versus $28.14/MWh) and 14.3% higher than in When hourly load levels are reflected, the load-weighted LMP of $36.65/MWh in 2001 was 19.3% higher than in 2000 and 7.6% higher than in 1999 (Table 3 below). The load weighted result reflects the fact that market participants typically purchase more energy during high price periods. However, when increased fuel costs are accounted for, the average fuel cost adjusted, load-weighted LMP in 2001 was 7.6% higher than in 2000, that is, $33.05/MWh compared to $30.72/MWh. Table 3: PJM Load-Weighted Average LMP ($/MWh) Year Over Year Percent Change Average LMP Median LMP Standard Deviation Average LMP Median LMP Standard Deviation % 8.1% 132.9% % 7.8% -69.0% % 22.3% 101.8% Ancillary services prices and capacity prices The MMU concluded that the regulation market functioned effectively and was competitive in The price of regulation in the market was approximately equal to the price under the administrative and cost-based system, and the price exhibited the expected relationship to changes in demand. There is the potential for various forms of non-competitive behavior in the energy market to affect the regulation market, although there is no evidence of such an issue during In the last quarter of 2000, the available supply of capacity in PJM exceeded the obligation to purchase capacity. Daily capacity prices were approximately zero from October 1, 2000 to December 31, From January 1, 2001 through March 31, 2001, the capacity credit market was much tighter and the daily capacity credit markets averaged about $177/MW-day for the period. In late March the price began to decline, reaching zero in early April. From January through the beginning of April 2001, the price in the daily PJM capacity credit market exceeded the spread between the PJM West hub and both Cinergy and N.Y. Zone A, valued over 16 hours. 14

23 Net revenue (load paid price minus operating costs) and trend Net revenue is an indicator of the profitability of an investment in generation. In 2001, the net revenues would have more than fully covered the fixed costs of peaking units with operating costs of about $45/MWh and which ran during all profitable hours. The results in 2001 reflect both higher energy prices than in 2000 and higher capacity market prices that resulted in significant part from the exercise of market power during the first quarter of Average prices in 2001 exceeded those in both 2000 and 1999 for every marginal costs level, which explains why the net revenue curve for 2001 is higher for marginal cost levels less than about $35/MWh. Generators receive capacity related revenues in addition to energy related revenues. In 2001, PJM Capacity Resources received a weighted average payment from all capacity markets of $95.34/MW-day, or $36,700/MW for the year. In 2000, the average payment from the capacity markets was $60.55/MW-day or $23,308/MW-year. Price-cost mark-up [(Price-marginal cost)/price] and trend The price-cost markup is a widely used measure of market power. For the adjusted markup index, the average markup in 2001 was 11% in 2001, with a maximum mark up of 13% in January and a minimum markup of 9 % in October. If the marginal unit is a combustion turbine with a price offer equal to $500/MWh and the highest marginal cost of an operating unit is $130/MWh, the observed price-cost markup index would be 74% (( )/500). Coal and miscellaneous fuel units had average markups of between 10% and 9% during In 2001, coal-fired units were on the margin 49% of the time, petroleum-fired units 32% of the time, gas-fired units 18% of the time and nuclear units 1% of the time. Petroleum-fired units share of marginal usage increased from 31% in 2000 to 32% in 2001; the share of coal also increased by about 1%; the shares of nuclear; and the share of natural gas was unchanged. Congestion costs and trend Congestion costs in PJM increased significantly, from $53M in 1999 to $271M in This increase can be attributed to different patterns of generation, imports and load and, in particular, the increased frequency of congestion at PJM s Western Interface, which affects about 75% of PJM load. Market power abuse investigation and mitigation The capacity markets experienced a significant market power issue in the beginning of the year. This represented a price increase of 57.9% over The weighted average annual capacity prices reflect the exercise of market power during the first portion of Operation inefficiency The need to procure day-ahead unit commitments to conduct security-constrained dispatch in the day-ahead market could increase uplift significantly. Market participants can manipulate LMP by submitting artificial schedules. About 21% energy trading at the real-time market, plus 40% of dispatch noncompliance (in 2000), increase operational difficulty in the real-time and 15

24 probably increase regulation costs. Multi-solution of LMP and high price correction rate (4.6% in 1999) reduce the benefit of LMP price signals. Load participation Active Load Management (ALM) reflects the ability of individual customers, under contract with their local utilities, to reduce specified amounts of load when PJM declares an emergency. ALM credits, measured in MW of curtailable load, reduce an LSE s capacity obligation. In 2001, ALM credits averaged 1,851 MW, up slightly from the level of 1,819 MW in New entry and capacity construction From 1997 to 2000, annual capacity additions averaged almost 800 MW a cumulative growth rate of 4.2%. This growth was more than double the 2% average rate of peak demand growth during this period. The short-term outlook for capacity additions sum to 23,339 MW by summer of 2004 based on requested studies. Non-Load Serving Entities are supplying most new generation additions. During 2001, Capacity Resources exceeded capacity obligation by approximately 1,300 MW on average. PJM was capacity deficient for three days in January. Potential Areas of Improvements in PJM Market The MMU in PJM Annual Report recommended: 1. Evaluation of additional actions to increase demand side responsiveness to price in both energy and capacity markets and actions to address institutional issues which may inhibit the evolution of demand side price response. 2. Modification of the FTR allocation method to eliminate any barriers to retail competition. 3. Development of an approach to identify areas where transmission expansion investments would relieve congestion where that congestion may enhance generator market power and where such investments are needed to support competition. 4. Continued enhancements to the capacity market to stimulate competition, adoption of a single capacity market design and incorporation of explicit market power mitigation rules to limit the ability to exercise market power in the capacity market. 5. Retention of the $1,000/MWh bid cap in the PJM energy market and investigation of other rules changes to reduce the incentives to exercise market power. 6. Retention of the $100/MW bid cap in the PJM regulation market. MOD Staff observations 1. It is reported that market power exercises and threats exist in the ICAP market and spot energy market. Larger energy trading in the spot energy market (energy pool) with virtual trading provides gaming opportunities for generators to manipulate LMP and FTR value by submitting schedules with misrepresentation of generator characteristics (i.e., ramping, minimum output). LMP makes market power mitigation more difficult since changes of bid components have impact not only on a specific bus but on the whole network as well. 16

25 2. The simple hourly average system wide LMP was 15.1% higher in 2001 than in After accounting for both the actual pattern of loads and the increased costs of fuel, average prices in PJM were 7.6% higher in 2001 than in 2000, which means suppliers profits increased 76% if we assume that they earned 10% margin in Increased congestion costs ($53 million in 1999 to $271 million in 2001) indicate that market participants did not change their scheduling behavior to avoid congestion based on the day-ahead price signals. 4. The ISO needs to procure a large amount of day-ahead unit commitment to conduct security-constrained dispatch in the day-ahead market, which could significantly increase uplift to loads. 5. Twenty-one percent of energy trading at the real-time market plus 40% of dispatch noncompliance (in 2000) significantly increases operational difficulties in real-time and probably increase costs of regulation services. 2. New York Independent System Operator Market The New York Independent System Operator (NYISO) is a non-profit organization formed as part of the restructuring of New York State s electric power industry. 6 The NYISO officially assumed control and operation of the state s power grid on December 1, 1999, replacing the New York Power Pool, which had operated the statewide, centrally-dispatched power pool for over 30 years. The NYISO is responsible for the operation of New York s high-voltage transmission grid and the administration of a wholesale electricity market in which power is purchased and sold at market-based prices. NYISO supplies 157,000 GWh of electric loads annually with a peak load of about 30,983 MW and installed capacity of more than 35,000 MW. The NYISO operates both a day-ahead and a real-time energy market, which together are known as the two-settlement system. Energy transactions and transmission usage scheduled in each of these markets are settled using Locational Based Marginal Prices (LBMPs). The day-ahead market determines LBMPs at each generator bus and for each load zone for each hour of the next day with simultaneously procuring and optimizing ancillary services. The real-time market determines the spot price used to settle real-time transactions and differences between day-ahead schedules and real-time generation and load. In addition to a day-ahead market and a real time energy market, the NYISO operates an hour-ahead Scheduling Model to facilitate market operation. The Scheduling Model includes processes to dispatch generation, procure ancillary services, schedule external transactions, and set market-clearing prices in the day-ahead and the real-time markets based on supply offers and demand bids. The NYISO also administers separate ICAP and Transmission Congestion Contract (TCC) markets. 6 Information in this section is based on (1) Feasibility Study for a Combined Day-Ahead Market in the Northeast by John P. Buechler, Scott M. Harvey, Susan L. Pope, Robert M. Thompson, April 20, 2001; (2) 2001 Annual Report on the New York Electricity Markets by David B. Patton and Michael T. Wander, Independent Market Advisor to the New York ISO, June 2002; (3) NYISO Market Operations Report, Business Issues Committee Meeting, October 23, 2002, Agenda #4; and (4) DRAFT TREATMENT OF DISTRIBUTED RESOURCES, NYISO-DSM Focus Group, Revised: November 16, Information was also found on the NYISO website: 17