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Pjm 2007 State of the Market Report
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2007 State of the Market Report Volume 1: INTRODUCTION Market Monitoring Unit March 11, 2008

2007 State of the Market Report Preface The Market Monitoring Unit of PJM Interconnection publishes an annual state of the market report that assesses the state of competition in each market operated by PJM, identifies specific market issues and recommends potential enhancements to improve the competitiveness and efficiency of the markets.

The 2007 State of the Market Report is the tenth such annual report. This report is submitted to the Board of PJM Interconnection pursuant to the PJM Open Access Transmission Tariff (OATT), Attachment M (PJM Market Monitoring Plan):

The Market Monitoring Unit shall prepare and submit to the PJM Board and to the PJM Members Committee, annual state-of-the-market reports on the state of competition within, and the efficiency of, the PJM Market. In such reports, the Market Monitoring Unit may make recommendations regarding any matter within its purview. The reports to the PJM Board shall include recommendations as to whether changes to the Market Monitoring Unit or the Plan are required.

The Market Monitoring Unit is submitting this report simultaneously to the United States Federal Energy Regulatory Commission per the Commissions order:

The Commission has the statutory responsibility to ensure that public utilities selling in competitive bulk power markets do not engage in market power abuse and also to ensure that markets within the Commissions jurisdiction are free of design flaws and market power abuse. To that end, the Commission will expect to receive the reports and analyses of an RTOs [regional transmission organizations] market monitor at the same time they are submitted to the RTO.

PJM, OATT, Attachment M: PJM Market Monitoring Plan, Third Revised Sheet No. 452 (Effective July 17, 2006).

96 FERC ¶ 61,061 (2001).

P r e fa c e 2007 State of the Market Report ii © PJM Interconnection 2008 l www.pjm.com

2007 State of the Market Report Table of Contents Introduction 1 PJM Market Background 2 Conclusions 2 Recommendations 2 Continued Action 2 New Action 4 Energy Market, Part 1 6 Market Structure 7 Market Conduct 8 Market Performance: Markup, Load and Locational Marginal Price 8 Demand-Side Response 9 Conclusion 10 Energy Market, Part 2 12 Net Revenue 12 Existing and Planned Generation 13 Scarcity 14 Credits and Charges for Operating Reserve 15 Conclusion 16 Interchange Transactions 17 Interchange Transaction Activity 17 Interchange Transaction Topics 18 Interchange Transaction Issues 20 Conclusion 22 Capacity Market 23 Capacity Credit Market 24 RPM Capacity Market 25 Generator Performance 29 Conclusion 29 Ancillary Service Markets 30 Regulation Market 31 Conclusion 34 Congestion 36 Congestion Cost 37 Congestion Component of LMP and Facility or Zonal Congestion 37 Economic Planning Process 39 Conclusion 40 Financial Transmission and Auction Revenue Rights 41 FTRs 41 ARRs 43 Conclusion 45

Ta b l e o f C o n t e n t s 2007 State of the Market Report iv © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I Introduction The PJM Interconnection, L.L.C. operates a Michigan, New Jersey, North Carolina, Ohio, centrally dispatched, competitive wholesale electric Pennsylvania, Tennessee, Virginia, West Virginia power market that, as of December 31, 2007, had and the District of Columbia. (See Figure 11.) As installed generating capacity of 163,498 megawatts part of that function, PJM coordinates and directs (MW) and more than 500 market buyers, sellers the operation of the transmission grid and plans and traders of electricity in a region including transmission expansion improvements to maintain approximately 51 million people in all or parts of grid reliability in this region.

Delaware, Illinois, Indiana, Kentucky, Maryland, Figure 11 PJMs footprint and its zones Legend Allegheny Power Company (AP) Jersey Central Power and Light Company (JCPL)

American Electric Power Co., Inc (AEP) Metropolitan Edison Company (Met-Ed)

Atlantic Electric Company (AECO) PECO Energy (PECO)

Baltimore Gas and Electric Company (BGE) Pennsylvania Electric Company (PENELEC)

ComEd Pepco Dayton Power and Light Company (DAY) PPL Electric Utilities (PPL)

Delmarva Power and Light (DPL) Public Service Electric and Gas Company (PSEG)

Rockland Electric Company (RECO)

Dominion Duquesne Light (DLCO)

See the 2007 State of the Market Report, Volume II, Appendix A, PJM Geography for maps showing the PJM footprint and its evolution.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report PJM Market Background represents the analysis of PJMs independent Market Monitoring Unit (MMU).

PJM operates the Day-Ahead Energy Market, the Real-Time Energy Market, the Reliability Pricing The MMU concludes that in 2007:

Model (RPM) Capacity Market, the Regulation Market, the Synchronized Reserve Markets and the

The Energy Market results were competitive; Annual and monthly Balance of Planning Period Auction Markets in Financial Transmission Rights

The Capacity Market results were competitive; (FTRs).

The Regulation Market results cannot be PJM introduced energy pricing with cost-based determined to have been competitive or to offers and market-clearing nodal prices on April 1, have been noncompetitive; 1998, and market-clearing nodal prices with market-based offers on April 1, 1999. PJM

The Synchronized Reserve Markets results introduced the Daily Capacity Market on January 1, were competitive; and 1999, and the Monthly and Multimonthly Capacity Markets in mid-1999. PJM implemented an auction-

The FTR Auction Market results were based FTR Market on May 1, 1999. PJM competitive.

implemented the Day-Ahead Energy Market and the Regulation Market on June 1, 2000. PJM Recommendations modified the regulation market design and added a market in spinning reserve on December 1, 2002. The MMU recommends retention of key market PJM introduced an Auction Revenue Rights (ARR) rules, specific enhancements to those rules and allocation process and an associated Annual FTR implementation of new rules that are required for Auction effective June 1, 2003. PJM introduced continued competitive results in PJM markets and the RPM Capacity Market effective June 1, 2007. for continued improvements in the functioning of PJM markets. The recommendations are for Volume I of the 2007 State of the Market Report is continued action where PJM has already identified the Introduction. More detailed analysis and results areas for improvement and for new action in areas are included in Volume II. where PJM has not yet identified a plan.

Conclusions Continued Action This report assesses the competitiveness of the

Retention and application of the improved local markets managed by PJM during 2007, including market power mitigation rules to prevent the market structure, participant behavior and market exercise of local market power in the Energy performance. This report was prepared by and Market while ensuring appropriate economic signals when investment is required.

See also the 2007 State of the Market Report, Volume II, Appendix B, PJM Market Milestones. PJM applies the three pivotal supplier test to

Analysis of 2007 market results requires comparison to 2006 and to certain prior years. During calendar years 2004 and 2005, PJM conducted the phased determine whether local energy markets are integration of five control zones: ComEd, American Electric Power (AEP), The Dayton Power & Light Company (DAY), Duquesne Light Company (DLCO) and structurally competitive. The three pivotal Dominion. By convention, control zones bear the name of a large utility service provider working within their boundaries. The nomenclature applies to the supplier test, as implemented, is consistent geographic area, not to any single company. For additional information on the integrations, their timing and their impact on the footprint of the PJM service with the United States Federal Energy territory, see the 2007 State of the Market Report, Volume II, Appendix A, PJM Geography.

Regulatory Commissions (FERCs) market

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I power tests, encompassed under the delivered Market design explicitly allows competitive price test. The test is a flexible, targeted real- prices to reflect local scarcity without relying on time measure of market structure which the exercise of market power to achieve the replaced the previous mitigation method of objectives of the Capacity Market design and offer capping of all units required to relieve a explicitly limits the exercise of market power via constraint. The application of the three pivotal the application of the three pivotal supplier supplier test successfully limits offer capping in test.

the Energy Market to situations where the local market is structurally noncompetitive and

Implementation of enhancements to PJMs where specific owners have structural market rules governing operating reserve credits to power, except in cases where either specific generators.

units or interfaces are exempt from the application of this rule. The operating reserve rules should ensure that credits and corresponding charges to market

Retention of the $1,000 per MWh offer cap in participants are consistent with incentives for the PJM Energy Market and other rules that efficient market outcomes and should reduce limit incentives to exercise market power. gaming incentives. PJM is expected to file proposed changes, approved by the The PJM market design includes a variety of membership, to the operating reserve rules rules that effectively limit the incentive to with the FERC in 2008.

exercise market power and ensure competitive outcomes. These should be retained and

Continued enhancements to the cost-benefit enforced and any proposed PJM market rule analysis of congestion and transmission change should be evaluated for its impact on investments to relieve congestion, especially competitive outcomes. where that congestion may enhance generator market power and where such investments

Retention and application of the rules included support competition.

in PJMs RPM Tariff to stimulate competition, to provide direct incentives for performance, to PJM has significantly improved its approach to provide locational price signals, to provide the cost-benefit analysis of transmission forward auctions to permit competition from investments. PJM should continue to evaluate new entrants and to limit market power by the critically its approach, particularly as it applies application of clear and explicit market power to constraints with large and persistent market mitigation rules. Implementation of impacts. New transmission projects and the enhancements to incentives for capacity lack of existing transmission can have significant resource performance to ensure stronger, impacts on the PJM markets. The goal of market-based incentives for actual performance transmission planning should ultimately be the when needed. incorporation of transmission investment decisions into market-driven processes as Market power remains a serious concern in the much as is practicable.

PJM Capacity Market based on market structure conditions in this market including

Modification of rules governing demand-side high levels of supplier concentration, frequent programs to ensure appropriate levels of occurrences of pivotal suppliers and extreme payment and to ensure appropriate inelasticity of demand. The RPM Capacity measurement and verification of demand-side

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report response. Evaluation of additional actions to Changes in net interchange affect PJM address institutional issues which may inhibit operations and markets as they require the evolution of demand-side price response. increases or decreases in generation to meet load. As a result of the fact that ramp is free but PJM and the MMU should continue efforts to is a valuable resource, there are strong ensure that market power is not exercised on incentives to game the ramp rules. The same is the demand side of the market, particularly via true of spot import service.

gaming of the measurement and verification process. The rules governing measurement

Continued enhancement of PJMs posting of and verification need to be tightened market data to promote market efficiency.

substantially. The principal barriers to the further development of demand-side response PJM has expanded the types and extent of are in the interface between wholesale and data posted to the Web for public access. PJM retail markets. should continue to expand data posting consistent with the goal of improving market

Provision of data to PJM from external control efficiency and stimulating competition.

areas to enable improved analysis of loop flows in order to enhance the efficiency of PJM

Based on the outcome of the active, public markets. process that addressed the independence of market monitoring during the MMUs ninth PJM and other control area operators have year, the MMU is confident that the market only limited access to the data required for a monitoring function will be independent, well-complete analysis of loop flow in the Eastern organized, well-defined, clear to market Interconnection. Provision of such data access participants and consistent with the policies of and completion of the loop flow analysis could the FERC.,

significantly enhance the transparency and efficiency of energy markets in both market New Action and non market areas and the efficiency of transactions between market and non market

Enhancements to PJMs scarcity pricing rules areas as well as permit market-based to create locational scarcity pricing signals in congestion management across the Eastern place of regional scarcity signals and to create Interconnection. Loop flows have negative stages of scarcity with corresponding stages impacts on the efficiency of market prices in of scarcity pricing in order to ensure competitive markets with explicit locational pricing and can prices when scarcity conditions exist in market be evidence of attempts to game such markets. regions.

Loop flows also have poorly understood impacts on non market areas. PJM has taken The MMU reviewed the summer of 2007 for some actions to address this issue and should scarcity conditions and the market prices that give a high priority to continued actions to resulted. Based on the results, the MMU achieve this. recommends that PJMs scarcity pricing mechanism be reviewed and modified. The

Continued enhancement of mechanisms used to manage flows at the interfaces between PJM. Open Access Transmission Tariff (OATT), Attachment M: PJM Market Monitoring Plan, Third Revised Sheet No. 452 (Effective July 17, 2006). Section PJM and surrounding areas. VII.A. states: The reports to the PJM Board shall include recommendations as to whether changes to the Market Monitoring Unit or the Plan are required.

On December 19, 2007, the parties filed a settlement with the Federal Energy Regulatory Commission, pursuant to the September 20, 2007, order in Docket Nos. EL07-56-000 and EL07-58-000 (consolidated).

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I definition of scarcity should include several dominant suppliers in every hour. The MMU stages of scarcity, each with an associated also recommends that all suppliers be required administrative price, rather than the single step to provide cost-based regulation offers, now in the Tariff. Scarcity pricing should include consistent with the practice in the Energy stages, based on system conditions, with Market.

progressive impacts on prices. In addition, the actual market signal needs further refinement.

Consistent application of local market power Under the current rules, a scarcity pricing event rules to all constraints.

sets prices for all generators in the defined area at the same level, equal to the highest accepted The MMU recommends that the Commission offer within a scarcity pricing region. The single terminate the exemption from offer capping scarcity price signal should be replaced by currently applicable to generation resources locational signals that are consistent with used to relieve the western, central and eastern economic dispatch, consistent with locational reactive limits in the PJM Mid-Atlantic control pricing and consistent with competitive market zones and the AP South Interface. The MMU outcomes. PJM should also consider adding recommends that all constraints, including new scarcity pricing regions. these interfaces, be subject to three pivotal supplier testing as specified in the PJM

Implementation of targeted, flexible real-time, Amended and Restated Operating Agreement market power mitigation in the Regulation (OA). The exemptions for the identified Market. interfaces are no longer necessary given PJMs dynamic implementation of the three pivotal The MMU concludes from the analysis of the supplier test based on actual market conditions 2007 data that the PJM Regulation Market in in real time. It is not necessary to make an ex 2007 was characterized by structural market ante decision about the market structure power in 80 percent of the hours, based on the associated with individual interface constraints results of the three pivotal supplier test. The that applies for an extended period. Prior to the MMU concludes that it would be preferable to implementation of the three pivotal supplier retain the existing, experimental single PJM test, all units required to resolve a constraint Regulation Market as the long-term market if were offer capped. For the identified exempt appropriate mitigation can be implemented. interfaces, this could have resulted in the offer Such mitigation, in the form of the three pivotal capping of a large number of units even when supplier test, addresses only the hours in which the relevant market was structurally competitive.

structural market power exists and therefore That is no longer the case. Under the current provides an incentive for the continued PJM dynamic approach, offer capping will be development of competition. While suppliers applied only as necessary and will be applied have not provided data on their cost to regulate, on a nondiscriminatory basis for all units an analysis of the Regulation Market based on operating for all constraints. It would be the MMUs cost estimates, adjusted to reflect reasonable to implement this change at the the modified cost definitions implemented in same time as the recommended changes to 2007, indicates that offers above the the scarcity pricing rules.

competitive level set the clearing prices in 26 percent of the hours. The combined market

Consistent application of local market power results include the effects of the current rules to all units, including those currently mitigation mechanism which offer caps the two exempt from offer capping.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report PJMs offer-capping rules provide that specific Energy Market, Part 1 units are exempt from offer capping, based on their date of construction. In a January 25, The PJM Energy Market comprises all types of 2005, order, the FERC found that the energy transactions, including the sale or purchase exemption for post-1996 units from the offer of energy in PJMs Day-Ahead and Real-Time capping rules is unjust and unreasonable under Energy Markets, bilateral and forward markets and section 206 of the Federal Power Act and that self-supply. Energy transactions analyzed in this the just and reasonable practice under section report include those in the PJM Day-Ahead and 206 is to terminate the exemption, with Real-Time Energy Markets. These markets provide provisions to grandfather units for which key benchmarks against which market participants construction commenced in reliance on the may measure results of transactions in other exemption. The FERC noted, however, that markets.

grandfathered units would still be subject to mitigation in the event that PJM or its market The MMU analyzed measures of market structure, monitor concludes that these units exercise participant conduct and market performance for significant market power. A small number of 2007, including market size, concentration, residual exempt units accounted for a disproportionate supply index, price-cost markup, net revenue and share of markup in 2007. Eight exempt units price. The MMU concludes that the PJM Energy accounted for 20 percent of the overall markup Market results were competitive in 2007.

component of PJM prices in 2007.

PJM markets are designed to promote competitive The rationale for grandfathering the specific 56 outcomes derived from the interaction of supply exempt units was that their owners might have and demand in each of the PJM markets. Market relied on the exemption in deciding whether to design itself is the primary means of achieving and invest. Given the substantial changes in PJM promoting competitive outcomes in PJM markets.

markets, including the introduction of the RPM One of the MMUs primary goals is to identify actual Capacity Market and scarcity pricing, the or potential market design flaws. PJMs market rationale for grandfathering no longer holds. power mitigation goals have focused on market The combination of RPM and scarcity pricing designs that promote competition (a structural has had a substantial impact on unit revenues, basis for competitive outcomes) and on limiting as demonstrated in the Net Revenue section market power mitigation to instances where the of the 2007 State of the Market Report. Rather market structure is not competitive and thus where than devise a special market power test for market design alone cannot mitigate market power.

exempt units or go through a separate process In the PJM Energy Market, this occurs only in the for each such unit, it would be reasonable to case of local market power. When a transmission remove the exemption on a going forward constraint creates the potential for local market basis. power, PJM applies a structural test to determine if the local market is competitive, applies a behavioral test to determine if generator offers exceed competitive levels and applies a market performance test to determine if such generator offers would affect the market price.

110 FERC ¶ 61,053 (2005).

See PJM. Open Access Transmission Tariff (OATT), Attachment M: Market

110 FERC ¶ 61,053 (2005). Monitoring Plan, Third Revised Sheet No. 452 (Effective July 17, 2006).

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I Market Structure ratios indicate comparatively smaller numbers of sellers dominating a market, while low

Supply. During the June to September 2007 concentration ratios mean larger numbers of summer period, the PJM Energy Market sellers splitting market sales more equally. High received an hourly average of 154,944 MW in concentration ratios indicate an increased net supply including hydroelectric generation. potential for participants to exercise market The summer 2007 net supply was 615 MW power, although low concentration ratios do lower than the summer 2006 net supply of not necessarily mean that a market is 155,559. The decrease was comprised of 377 competitive or that participants cannot exercise MWh of decreased hydroelectric power market power. Analysis of the PJM Energy generation and 237 MWh of reduced offers Market indicates moderate market from non-hydroelectric capacity.10 concentration overall. Analyses of supply curve segments indicate moderate concentration in Figure 12 Average PJM aggregate supply curves: the baseload segment, but high concentration Summers 2006 and 2007 in the intermediate and peaking segments.

$1,000 2006 Peak load

Local Market Structure and Offer Capping.

2007 Peak load

$900 Avg Jun-Sep 2006 Noncompetitive local market structure is the

$800 Avg Jun-Sep 2007

$700 trigger for offer capping. PJM implemented a Price ($/MWh)

$600 flexible, targeted, real-time approach to offer

$500

$400 capping (the three pivotal supplier test) as the

$300

$200 trigger for offer capping in 2006 and continued

$100 to apply the test in 2007. PJM offer caps units

$0 0

10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 only when the local market structure is 100,000 110,000 120,000 130,000 140,000 150,000 160,000 Quantity (MW) noncompetitive. Offer capping is an effective means of addressing local market power. Offer-capping levels have historically been low in

Demand. The PJM system peak load in 2007 PJM. In the Day-Ahead Energy Market offer-was 139,428 MW in the hour ended 1600 EPT capped unit hours fell from 0.4 percent in 2006 on August 8, 2007, while the PJM peak load in to 0.2 percent in 2007. In the Real-Time Energy 2006 was 144,644 in the hour ended 1700 on Market offer-capped unit hours rose from 1.0 August 2, 2006.11 The 2007 peak load was percent in 2006 to 1.1 percent in 2007. (See 5,216 MW, or 3.6 percent, lower than the 2006 Table 11.)

peak load. (See Figure 12.)

Local Market Structure. A summary of the

Market Concentration. Concentration ratios results of PJMs application of the three pivotal are a summary measure of market share, a key supplier test is presented for all constraints element of market structure. High concentration which occurred for 100 or more hours during calendar year 2007. The analysis of the application of the three pivotal supplier test to

Calculated values shown in the 2007 State of the Market Report, Volume 1, Introduction are based on unrounded, underlying data and may differ from local markets demonstrates that it is working calculations based on the rounded values shown in tables.

successfully to exempt owners when the 10 The 2006 State of the Market Report reported a summer 2006 net capacity of 155,600 MW, which was rounded to the nearest 100 MW. market structure is competitive and to offer 11 For the purpose of Volume I and Volume II of the 2007 State of the Market Report, all hours are presented and all hourly data are analyzed using Eastern cap only pivotal owners when the market Prevailing Time (EPT). See Appendix M, Glossary, for a definition of EPT and its relationship to Eastern Standard Time (EST) and Eastern Daylight Time (EDT).

structure is noncompetitive.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Specific geographic areas of PJM exhibited power. A positive markup by marginal units will moderate to high levels of concentration when result in a difference between the observed transmission constraints defined local markets. market price and the competitive market price.

While PJMs local market power mitigation The annual average markup index was 0.09 rules prevented the exercise of market power with a monthly average maximum of 0.22 in in these circumstances, the rules do not apply June and a monthly average minimum of 0.03 to units exempt from offer capping and in January. The overall results support the therefore did not prevent the exercise of market conclusion that prices in PJM are set, on power by a small number of such units. average, by marginal units operating at or close to their marginal costs. This is strong evidence Table 11 Annual offer-capping statistics: Calendar of competitive behavior.

years 2003 to 2007 Market Performance: Markup, Load Real Time Day Ahead and Locational Marginal Price Unit Hours MW Unit Hours MW Capped Capped Capped Capped

Markup. The markup conduct of individual 2003 1.1% 0.3% 0.4% 0.2%

owners and units has an impact on market 2004 1.3% 0.4% 0.6% 0.2%

prices that is not measured by the price-cost 2005 1.8% 0.4% 0.2% 0.1% markup index. The MMU calculates explicit 2006 1.0% 0.2% 0.4% 0.1% measures of the impact of marginal unit 2007 1.1% 0.2% 0.2% 0.0% markups on LMP. The LMP impact is a measure of market power. The price impact of markup

Characteristics of Marginal Units. The must be interpreted carefully. The price impact concentration of ownership of all marginal units is not based on a full redispatch of the system, in the Energy Market provides additional but such a full redispatch is practically information about market structure. The higher impossible as it would require reconsideration the level of concentration of ownership of of all dispatch decisions and unit commitments.

marginal units, the greater is the potential The markup impact includes the maximum market power issue. In 2007, the top four impact of the identified markup conduct on a companies accounted for 40 percent of the unit-by-unit basis, but the inclusion of negative systems load-weighted, average locational markup impacts has an offsetting effect. The marginal price (LMP). markup analysis does not distinguish between intervals in which a unit has local market power In 2007, coal-fired units accounted for 70 or has a price impact in an unconstrained percent of marginal units and natural gas-fired interval. The markup analysis is a more general units accounted for 24 percent of all marginal measure of the competitiveness of the Energy units. Market.

Market Conduct The markup component of the overall system load-weighted, average LMP was $5.86 per

Price-Cost Markup. The price-cost markup MWh, or 10 percent. The markup was $8.59 index is a measure of conduct or behavior by per MWh during peak hours and $2.91 per the owners of generating units and not a MWh during off-peak hours. The overall results measure of market impact. For marginal units, support the conclusion that prices in PJM are the markup index is a measure of market set, on average, by marginal units operating at

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I or close to their marginal costs. This is strong cost-adjusted, load-weighted, average LMP evidence of competitive behavior and was 18.1 percent higher in 2007 than in 2006, competitive market performance. $63.00 per MWh compared to $53.35 per MWh. Fuel costs in 2007 contributed to A substantial portion of the markup, $0.57 per downward pressure on LMP rather than MWh or 10 percent occurred on high-load upward pressure.

days during the summer of 2007. Markup on high-load days is likely to be the result of

Load and Spot Market. Real-time load is appropriate scarcity pricing rather than market served by a combination of self-supply, bilateral power. market purchases and spot market purchases.

From the perspective of a single PJM billing The units that are exempt from offer capping organization that serves load, its load could be for local market power accounted for $1.34 supplied by any combination of its own per MWh, or 23 percent, of the markup for all generation, net bilateral market purchases and days. This is a disproportionate share, given net spot market purchases. For 2007, 95.9 that only 44 of 56 exempt units were marginal percent of real-time load was supplied by and that only eight exempt units of the 44 bilateral contracts, 3.9 percent by spot market accounted for $1.15, or 86 percent, of this purchases and 0.2 percent by self-supply.

markup component of price. The average Compared with 2006, reliance on bilateral markup per exempt unit is about four times contracts increased by 3.1 percentage points; higher than for non-exempt units, and the reliance on spot supply decreased by 2.3 average markup for the top eight exempt units percentage points and reliance on self-supply is about 21 times higher than for non-exempt decreased by 0.8 percentage points in 2007.

units.

Demand-Side Response

Load. On average, PJM real-time load increased in 2007 by 2.8 percent over 2006,

Demand-Side Response (DSR). Markets rising from 79,471 MW to 81,681 MW. require both a supply side and a demand side to function effectively. PJM wholesale market,

Prices. PJM LMPs are a direct measure of demand-side programs should be understood market performance. Price level is a good, as one relatively small part of a transition to a general indicator of market performance, fully functional demand side for its Energy although the number of factors influencing the Market. A fully developed demand side will overall level of prices means it must be analyzed include retail programs and an active, well-carefully. For example, overall average prices articulated interaction between wholesale and subsume congestion and price differences retail markets. There are significant issues with over time. the current approach to measuring demand-side response MW, which is the basis on which PJM Real-Time Energy Market prices rose in program participants are paid. The current 2007 over 2006. The system simple average approach can lead to payments when the LMP was 16.9 percent higher in 2007 than in customer has taken no action to respond to 2006, $57.58 per MWh versus $49.27 per market prices. A substantial improvement in MWh. The load-weighted LMP was 15.6 measurement and verification methods must percent higher in 2007 than in 2006, $61.66 be implemented in order to ensure the credibility per MWh versus $53.35 per MWh. The fuel- of PJM demand-side programs. Total demand-

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report side response resources available in PJM on Prices are a key outcome of markets. Prices vary August 8, 2007 (the peak day in 2007), were across hours, days and years for multiple reasons.

2,145.30 capacity MW and 9.25 energy MW Price is an indicator of the level of competition in a from the Emergency Load-Response Program market although individual prices are not always and 2,498.03 energy MW from the Economic easy to interpret. In a competitive market, prices Load-Response Program. are directly related to the marginal cost of the most expensive unit required to serve load. The markup Conclusion index is a direct measure of that relationship between price and marginal cost for individual unit The MMU analyzed key elements of PJM Energy offers. LMP is a broader indicator of the level of Market structure, participant conduct and market competition. While PJM has experienced price performance for calendar year 2007, including spikes, these have been limited in duration and, in aggregate supply and demand, concentration general, prices in PJM have been well below the ratios, local market concentration ratios, price-cost marginal cost of the highest cost unit installed on markup, offer capping, participation in demand- the system. The significant price spikes in PJM side response programs, loads and prices in this have been directly related to scarcity conditions. In section of the report. The next section continues PJM, prices tend to increase as the market the analysis of the PJM Energy Market including approaches scarcity conditions as a result of additional measures of market performance. generator offers and the associated shape of the aggregate supply curve. The pattern of prices within Aggregate supply decreased by about 600 MW days and across months and years illustrates how when comparing the summer of 2007 to the prices are directly related to demand conditions summer of 2006 while aggregate peak load and thus also illustrates the potential significance of decreased by 5,216 MW, modifying the general price elasticity of demand in affecting price.

supply-demand balance from 2006 with a corresponding impact on-peak Energy Market The three pivotal supplier test is applied by PJM on prices. Overall load was higher than in 2006 and an ongoing basis for local energy markets in order there were twice as many high-load days, with a to determine whether offer capping is required for corresponding impact on overall average prices. constraints not exempt from offer capping. This is a Market concentration levels remained moderate flexible, targeted real-time measure of market and average markups remained relatively low structure which replaced the offer capping of all although markups increased. A small number of units required to relieve a constraint. A generation units exempt from offer capping accounted for a owner or group of generation owners is pivotal for a disproportionate share of the system markup. This local market if the output of the owners generation relationship between supply and demand, facilities is required in order to relieve a transmission regardless of the specific market, balanced by constraint. When a generation owner or group of market concentration, is referred to as supply- owners is pivotal, it has the ability to increase the demand fundamentals or economic fundamentals. market price above the competitive level. The three The Energy Market was tighter than in 2006 and pivotal supplier test, as implemented, is consistent this explains, at least in part, higher prices and with the FERCs market power tests, encompassed higher markups in 2007. While the market structure under the delivered price test. The three pivotal does not guarantee competitive outcomes, overall supplier test is an application of the delivered price the market structure of the PJM aggregate Energy test to both the Real-Time Market and hourly Day-Market remains reasonably competitive. Ahead Market. The three pivotal supplier test 10 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I explicitly incorporates the impact of excess supply nondiscriminatory basis for all units operating for all and implicitly accounts for the impact of the price constraints.

elasticity of demand in the market power tests.

The MMU also recommends that the FERC The result of the introduction of the three pivotal terminate the exemption from offer capping currently supplier test was to limit offer capping to times applicable to exempt units. PJMs offer-capping when the local market structure was noncompetitive rules provide that specific units are exempt from and specific owners had structural market power. offer capping, based on their date of construction.

The analysis of the application of the three pivotal In a January 25, 2005, order, the FERC had found supplier test demonstrates that it is working that the exemption for post-1996 units from the successfully to exempt owners when the local offer capping rules is unjust and unreasonable market structure is competitive and to offer cap under section 206 of the Federal Power Act and owners when the local market structure is that the just and reasonable practice under section noncompetitive. 206 is to terminate the exemption, with provisions to grandfather units for which construction The MMU recommends that the FERC terminate commenced in reliance on the exemption.13 The the exemption from offer capping currently FERC noted, however, that grandfathered units applicable to generation resources used to relieve would still be subject to mitigation in the event that the western, central and eastern reactive limits in PJM or its market monitor concludes that these the Mid-Atlantic Area Council (MAAC) control zones units exercise significant market power.14 Exempt and the AP South Interface.12 The MMU units exercised market power in 2006 and in recommends that all constraints, including these 2007.

interfaces, be subject to three pivotal supplier testing as specified in the PJM Amended and The rationale for grandfathering the specific 56 Restated Operating Agreement (OA). The exempt units was that their owners might have exemptions for the identified interfaces are no relied on the exemption in deciding whether to longer necessary given PJMs dynamic invest. Given the substantial changes in PJM implementation of the three pivotal supplier test markets, including the introduction of the RPM based on actual market conditions in real time. It is construct and scarcity pricing, the rationale for not necessary to make an ex ante decision about grandfathering no longer holds. The combination of the market structure associated with individual RPM and scarcity pricing has had a substantial interface constraints that applies for an extended impact on unit revenues, as demonstrated in the period. Prior to the implementation of the three Net Revenue section of the 2007 State of the pivotal supplier test, all units required to resolve a Market Report. Rather than devise a special market constraint were offer capped whenever the power test for exempt units or go through a separate constraint was binding. For the identified exempt process for each such unit, it would be reasonable interfaces, this could have resulted in the to remove the exemption on a going forward inappropriate offer capping of a large number of basis.

units even when the relevant market was structurally competitive. That is no longer the case. Under the Energy Market results, including prices, for 2007 current PJM dynamic approach, offer capping is generally reflected supply-demand fundamentals.

applied only as necessary and is applied on a Higher nominal and load-weighted prices are 13 110 FERC ¶ 61,053 (2005).

12 See PJM. Amended and Restated Operating Agreement (OA), Sections 6.4.1(d)(ii) and 6.4.1(e) (January 19, 2007). 14 110 FERC ¶ 61,053 (2005).

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report consistent with a competitive outcome as the higher Energy Market, Part 2 prices reflect higher overall demand and tighter supply-demand conditions. Fuel costs do not The MMU analyzed measures of PJM Energy explain the increase in prices in 2007. If fuel costs Market structure, participant conduct and market for the year 2007 had been the same as for 2006, performance for 2007. As part of the review of the 2007 load-weighted LMP would have been market performance, the MMU analyzed the net higher than it was. The overall market results revenue performance of PJM markets, the nature support the conclusion that prices in PJM are set, of new investment in capacity in PJM, the definition on average, by marginal units operating at, or close and existence of scarcity conditions in PJM and the to, their marginal costs. This is evidence of issues associated with operating reserve credits competitive behavior and competitive market and charges.

outcomes. Given the structure of the Energy Market, tighter markets or a change in participant Net Revenue behavior are potential sources of concern in the Energy Market. The MMU concludes that the PJM

Net Revenue Adequacy. Net revenue is an Energy Market results were competitive in 2007. indicator of generation investment profitability and thus is a measure of overall market Table 12 Components of PJM annual, load-weighted, performance as well as a measure of the average LMP: Calendar year 2007 incentive to invest in new generation to serve PJM markets. Net revenue quantifies the Element Contribution to LMP Percent contribution to capital cost received by Coal $21.57 35.0%

generators from all PJM markets. Although it Gas $17.50 28.4%

can be expected that in the long run, in a Oil $3.97 6.4%

competitive market, net revenue from all Wind $0.01 0.0% sources will cover the fixed costs of investing in SO2 $4.33 7.0% new generating resources, including a VOM $4.16 6.7% competitive return on investment, actual results Markup $5.86 9.5% are expected to vary from year to year.

Constrained off $3.13 5.1% Wholesale energy markets, like other markets, NOX $0.74 1.2% are cyclical. When the markets are long, prices NA $0.39 0.6% will be lower and when the markets are short, prices will be higher.

Overall, 2007 net revenue showed a significant increase over 2006. This was the result of higher prices in both the Energy and Capacity Markets. The levels of net revenue in 2007 for new peaking, midmerit and coal-fired baseload vary significantly by location. The fixed costs of constructing a new entrant combustion turbine, combined-cycle or coal-fired steam generation resource were fully covered in some, but not all, PJM control zones. There was revenue adequacy in 2007 for the combined-cycle (CC) technology for more zones than for either the 12 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I combustion turbine (CT) or pulverized-coal Pepco Control Zone and the minimum was (CP) technologies. Revenues associated with $41,958 in the AEP Control Zone. While the the sale of capacity resources increased PJM average net revenue in 2007 was significantly in 2007 as the result of the $277,284 per MW-year for a CP, the zonal introduction of the RPM construct. The results maximum net revenue was $384,940 in the from 2007 mark a reversal of the trend from the Pepco Control Zone and the minimum was prior eight-year period, 1999 to 2006. (See $157,544 in the DLCO Control Zone.

Table 13.) The increased net revenues in 2007 were the result of higher locational energy prices and of much higher locational capacity Existing and Planned Generation prices.15 Zonal net revenue reflects differences in locational energy prices and differences in

PJM Installed Capacity. During the period locational capacity prices. The zonal variation January 1, through December 31, 2007, PJM in net revenue illustrates the substantial impact installed capacity remained relatively flat.

of location on economic incentives. While the Retirements were offset by new additions and 2007 net revenue using PJM real-time average the installed capacity on December 31, 2007, LMPs was $48,530 per MW-year for a CT, the was only 658 MW more than on January 1, zonal maximum net revenue was $96,913 in 2007.

the Pepco Control Zone and the minimum was

$16,047 in the DAY Control Zone. While the

PJM Installed Capacity by Fuel Type. At the PJM average net revenue in 2007 was end of 2007, PJM installed capacity was

$100,809 per MW-year for a CC, the zonal 163,498 MW. Of the total installed capacity, maximum net revenue was $175,698 in the 40.5 percent was coal; 29.1 percent was Table 13 Total net revenue and 20-year, levelized fixed cost for new entry CT, CC and CP generators: Economic dispatch assumed CT CC CP Economic 20-Year Economic 20-Year Economic 20-Year Dispatch Net Levelized Dispatch Net Levelized Dispatch Net Levelized Revenue Fixed Cost Revenue Fixed Cost Revenue Fixed Cost 1999 $74,537 $72,207 $100,700 $93,549 $118,022 $208,247 2000 $30,946 $72,207 $47,592 $93,549 $134,564 $208,247 2001 $63,462 $72,207 $86,670 $93,549 $129,271 $208,247 2002 $28,260 $72,207 $52,272 $93,549 $112,131 $208,247 2003 $10,566 $72,207 $35,591 $93,549 $169,509 $208,247 2004 $8,543 $72,207 $35,785 $93,549 $133,124 $208,247 2005 $10,437 $72,207 $40,817 $93,549 $228,430 $208,247 2006 $14,948 $80,315 $49,529 $99,230 $182,461 $267,792 2007 $48,530 $90,656 $100,809 $143,600 $277,284 $359,750 Avg. $32,248 $75,158 $61,085 $99,741 $164,977 $231,697 15 For the eight-year period 1999 to 2006, capacity revenues were lower than during 2007 and generally decreasing with the exception of 2001 when market power issues affected prices.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report natural gas; 18.9 percent was nuclear; 6.5 Figure 13 High-load day hourly load and summer percent was oil; 4.5 percent was hydroelectric; average hourly load: June 2007 through August 2007 and 0.4 percent was solid waste.

Average hourly summer load 160,000 01-Jun-07 26-Jun-07

Generation Fuel Mix. During 2007, coal 140,000 27-Jun-07 09-Jul-07 10-Jul-07 provided 55.3 percent, nuclear 33.9 percent, 120,000 18-Jul-07 26-Jul-07 natural gas 7.7 percent, oil 0.5 percent, 100,000 27-Jul-07 30-Jul-07 31-Jul-07 hydroelectric 1.7 percent, solid waste 0.7 MW 80,000 01-Aug-07 02-Aug-07 percent and wind 0.2 percent of total 60,000 03-Aug-07 06-Aug-07 07-Aug-07 generation. 40,000 08-Aug-07 09-Aug-07 10-Aug-07 13-Aug-07 20,000 15-Aug-07

Planned Generation. If current trends continue, 16-Aug-07 17-Aug-07 0

it is expected that older steam units in the east 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 24-Aug-07 28-Aug-07 Hour ending (EPT) will be replaced by units burning natural gas 29-Aug-07 and the result has potentially significant implications for future congestion, the role of

Scarcity Pricing Events in 2007. In 2005 it firm and interruptible gas supply and natural was recognized that changing market dynamics gas supply infrastructure. created by PJMs expanded footprint, along with PJMs continued need for administratively Scarcity employed emergency mechanisms to maintain system reliability under conditions of scarcity,

Scarcity. There were 157 hours0.00182 days 0.0436 hours 2.595899e-4 weeks 5.97385e-5 months of high load had created a need for an administratively that occurred in 2007, of which 21 occurred in based, scarcity pricing mechanism. PJM June, 40 occurred in July and 96 occurred in implemented administratively based, scarcity August. This number of high-load hours is pricing rules in 2006.17 Based on the definition more than twice the 70 high-load hours in of scarcity in the Tariff, there were two official 2006. Within these 157 hours0.00182 days 0.0436 hours 2.595899e-4 weeks 5.97385e-5 months , there were three scarcity pricing events on August 8, 2007: one hours, the hours beginning 1500 through 1700, in the Bedington Black Oak Scarcity Pricing on August 8 that met the criteria for potential Zone between 1505 and 1812 and the other in within-hour scarcity.16 PJM triggered its scarcity the Mid-Atlantic Scarcity Pricing Region pricing events between 1505 and 1812. This between 1555 and 1733.

represents a clear improvement over 2006 when 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months met the criteria for potential

Modifications to Scarcity Pricing. While PJMs within-hour scarcity while no scarcity events triggers for administrative scarcity pricing are were triggered. reasonable measures of scarcity conditions, there are indications, based on the MMU analysis of 2007 market results, that PJMs current set of scarcity pricing rules need refinement. In addition, PJM should consider creating a mechanism for defining new scarcity pricing regions in real time if system conditions warrant. The MMU reviewed the summer of 2007 for scarcity conditions and the market prices that resulted. Based on the results, the MMU suggests that PJMs scarcity pricing 16 Scarcity is considered to exist when hourly demand, including a total operating reserve requirement, is greater than, or equal to, total, within-hour supply in the absence of non market administrative intervention. 17 114 FERC ¶ 61,076 (2006).

14 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I mechanism be reviewed and modified. The in order to ensure that units are not required to definition of scarcity should include several operate for the PJM system at a loss.

stages of scarcity, each with an associated Sometimes referred to as uplift or revenue administrative price, rather than the single step requirement make whole, operating reserve now in the Tariff. PJM should also consider payments are intended to be one of the adding new scarcity pricing regions. There incentives to generation owners to offer their would have been six hours of scarcity under energy to the PJM Energy Market at marginal PJM rules if BGE and Pepco had been defined cost and to operate their units at the direction to be a scarcity region. In addition, the actual of PJM dispatchers. From the perspective of market signal needs further refinement. The those participants paying operating reserve single scarcity price signal should be replaced charges, these costs are an unpredictable and by locational signals. Locational signals could unhedgeable component of the total cost of be implemented via scarcity offers submitted energy in PJM. While reasonable operating by generation owners. This would provide a reserve charges are an appropriate part of the means to signal scarcity that is consistent with cost of energy, market efficiency would be economic dispatch, consistent with locational improved by ensuring that the level of operating pricing and consistent with competitive market reserve charges is as low as possible consistent outcomes. Combined with a more refined set with the reliable operation of the system and of scarcity triggers, this approach would also that the allocation of operating reserve charges encourage participants to offer competitively reflects the reasons that the costs are under normal market conditions and incurred.

competitively in the context of scarcity conditions.

Operating Reserve Charges in 2007. The level of operating reserve credits and corresponding Credits and Charges for Operating charges increased in 2007 by 42.45 percent Reserve compared to 2006. The amount of balancing operating reserve credits paid to synchronous

Operating Reserve Issues. Day-ahead and condensing increased by 176.79 percent real-time operating reserve credits are paid to compared to 2006, 17.49 percent of the total generation owners under specified conditions net increase.

Table 14 Total day-ahead and balancing operating reserve charges: Calendar years 1999 to 2007 Operating Reserve Total Operating Annual Credit as a Percent of Total Day-Ahead Day-Ahead Balancing Balancing Reserve Credits Change PJM Billing $/MWh Change $/MWh Change 1999 $133,897,428 NA 7.5% NA NA NA NA 2000 $216,985,147 62.05% 9.6% $0.341 NA $0.535 NA 2001 $290,867,269 34.05% 8.7% $0.275 (19.5%) $1.070 100.2%

2002 $237,102,574 (18.48%) 5.0% $0.164 (40.4%) $0.787 (26.4%)

2003 $289,510,257 22.10% 4.2% $0.226 38.2% $1.197 52.0%

2004 $414,891,790 43.31% 4.8% $0.230 1.7% $1.236 3.3%

2005 $682,781,889 64.57% 3.0% $0.076 (66.9%) $2.758 123.1%

2006 $322,315,152 (52.79%) 1.5% $0.078 2.6% $1.331 (51.7%)

2007 $459,124,502 42.45% 1.5% $0.057 (27.0%) $2.331 75.1%

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Conclusion scarcity rents in the energy market, scarcity pricing can be a mechanism to appropriately increase Wholesale electric power markets are affected by reliance on the energy market as a source of externally imposed reliability requirements. A revenues and incentives in a competitive market regulatory authority external to the market makes a without reliance on the exercise of market power.

determination as to the acceptable level of reliability which is enforced through a requirement to maintain A capacity market is a formal mechanism, with both a target level of installed or unforced capacity. The administrative and market-based components, requirement to maintain a target level of installed used to allocate the costs of maintaining the level of capacity can be enforced via a variety of capacity required to maintain the reliability target. A mechanisms, including government construction of capacity market is an explicit mechanism for valuing generation, full-requirement contracts with capacity and is preferable to non market and developers to construct and operate generation, nontransparent mechanisms for that reason.

state utility commission mandates to construct capacity, or capacity markets of various types. While net revenue in PJM has been almost sufficient Regardless of the enforcement mechanism, the to cover the costs of new peaking units in some exogenous requirement to construct capacity in years and was sufficient to cover the costs of a new excess of what is constructed in response to energy coal plant in 2005 and close to covering those market signals has an impact on energy markets. costs in 2006 in some eastern zones, net revenue The reliability requirement results in maintaining a has generally been below the level required to cover level of capacity in excess of the level that would the full costs of new generation investment for result from the operation of an energy market alone. several years and below that level on average for all The result of that additional capacity is to reduce unit types for the entire market period. The fact that the level and volatility of energy market prices and investors expectations have not been realized in to reduce the duration of high energy market prices. every year could be taken as a reflection of cyclical This, in turn, reduces net revenue to generation supply-demand fundamentals in PJM markets.

owners which reduces the incentive to invest. However, it is also the case that there are some units in PJM, needed for reliability, that have had With or without a capacity market, energy market revenues that are not adequate to cover annual design must permit scarcity pricing when such going-forward costs and that their owners, pricing is consistent with market conditions and therefore, wish to retire. This suggests that market constrained by reasonable rules to ensure that price signals and reliability needs have not been market power is not exercised. Scarcity pricing is fully synchronized.

also part of an appropriate incentive structure facing both load and generation owners in a working The historical level of net revenues in PJM markets wholesale electric power market design. Scarcity is not the result of the $1,000-per-MWh offer cap, pricing must be designed to ensure that market of local market power mitigation, or of a basic prices reflect actual market conditions, that scarcity incompatibility between wholesale electricity pricing occurs in well-defined stages with markets and competition. Competitive markets transparent triggers and prices and that there are can, and do, signal scarcity and surplus conditions strong incentives for competitive behavior and through market-clearing prices. Nonetheless, in strong disincentives to exercise market power. PJM as in other wholesale electric power markets, Such administrative scarcity pricing is a key link the application of reliability standards means that between energy and capacity markets. With a scarcity conditions in the Energy Market occur with capacity market design that appropriately reflects reduced frequency. Traditional levels of reliability 16 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I require units that are only directly used and priced Interchange Transactions under relatively unusual load conditions. Thus, the Energy Market alone frequently does not directly PJM market participants import energy from, and value the resources needed to provide for reliability, export energy to, external regions continuously.

although the contribution of the Energy Market will The transactions involved may fulfill long-term or be more consistent with reliability signals if the short-term bilateral contracts or take advantage of Energy Market appropriately provides for scarcity short-term price differentials. The external regions pricing when scarcity does occur. include both market and non market control areas.

PJMs RPM is an explicit effort to address these Interchange Transaction Activity issues. RPM is a Capacity Market design intended to send supplemental signals to the market based

Aggregate Imports and Exports in the Real-on the locational and forward-looking need for Time Market. During 2007, PJM was a net generation resources to maintain system reliability exporter of energy in the Real-Time Market. In in the context of a long-run competitive equilibrium the Real-Time Market, monthly net interchange in the Energy Market. averaged -1,189 GWh.18 Gross monthly import volumes averaged 2,500 GWh while gross The combination of locational Energy Market and monthly exports averaged 3,689 GWh. (See locational Capacity Market signals in 2007 Figure 14.)

represented a significant change from market performance over prior years. The combined Figure 14 PJM scheduled import and export transaction locational prices clearly signaled a need for and an volume history: Calendar years 1999 to 2007 incentive for investment in eastern zones where 8,000 Gross imports Gross exports there is a demonstrated need for new capacity, Net interchange 6,000 although the results vary by technology. Net revenues exceeded the costs of all technologies in 4,000 Volume (GWh) the BGE and Pepco Control Zones and net revenues 2,000 exceeded the costs of CC technology in seven 0

eastern control zones.

-2,000 The ultimate test of a competitive market design is -4,000 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 whether it provides incentives to invest that are acted upon by market participants, based on incentives endogenous to the competitive market design and not in reliance on the potential or actual

Transactions in the Day-Ahead Energy exercise of market power. The net revenue Market. While PJM market participants performance of the Real-Time Energy Market, the historically imported and exported energy Day-Ahead Energy Market and the Capacity Market primarily in the Real-Time Energy Market, that prior to 2007 illustrated that additional market is no longer the case. In 2007, gross imports in modifications were necessary if PJM were to pass the Day-Ahead Energy Market were 85 percent that test. The performance of the markets in 2007, of the Real-Time Markets gross imports (77 especially the Capacity Markets, represented a percent in 2006) while gross exports in the significant improvement over prior performance.

The reaction of investors will determine whether the 18 Net interchange is gross import volume less gross export volume. Thus, positive market design modifications are successful. net interchange is equivalent to net imports and negative net interchange is equivalent to net exports.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Day-Ahead Market were 103 percent of the Interchange Transaction Topics Real-Time Markets gross exports (86 percent in 2006) and net interchange in the Day-Ahead

PJM Interface Pricing with Organized Energy Market exceeded net interchange in Markets.

the Real-Time Energy Market by 39 percent. In the Day-Ahead Market, monthly net interchange PJM and Midwest ISO Interface Pricing.

averaged -1,657 GWh. Gross monthly import During 2007, the relationship between volumes averaged 2,135 GWh while gross prices at the PJM/MISO Interface and at monthly exports averaged 3,792 GWh. the MISO/PJM Interface reflected economic fundamentals as did the

Interface Imports and Exports in the Real- relationship between interface price Time Market. In the Real-Time Market in 2007, differentials and power flows between there were net exports at 18 of PJMs 23 PJM and the Midwest ISO.

interfaces. The top three net exporting interfaces in the Real-Time Market accounted PJM and New York ISO Interface Pricing.

for 42 percent of the total net exports: PJM/ During 2007, the relationship between Tennessee Valley Authority (TVA) with 19 prices at the PJM/NYIS Interface and at percent, PJM/MidAmerican Energy Company the NYISO/PJM proxy bus reflected (MEC) with 12 percent and PJM/Neptune economic fundamentals as did the (NEPT) with 11 percent of the net export relationship between interface price volume. Five PJM interfaces had net imports, differentials and power flows between with two importing interfaces accounting for 95 PJM and NYISO. Both continued to be percent of net import volume: PJM/Ohio Valley affected by differences in institutional and Electric Corporation (OVEC) with 74 percent operating practices between PJM and and PJM/Duke Energy Corp. (DUK) with 21 NYISO.

percent.

PJM TLRs. The number of transmission

Interface Imports and Exports in the Day- loading relief procedures (TLRs) issued by PJM Ahead Market. In the Day-Ahead Market, there continued to decline, with 41 percent fewer were net exports at 16 of PJMs 23 interfaces. during 2007 (80) than 2006 (136). The reduction The top three net exporting interfaces in TLRs declared by PJM is consistent with the accounted for 54 percent of the total net fact that market signals, rather than market exports, PJM/Northern Indiana Public Service interventions, are being used more frequently Company (PJM/NIPS) with 27 percent, PJM/ to manage constraints on interarea transactions.

western Alliant Energy Corporation (ALTW) with However, more needs to be done to assure 16 percent and PJM/MEC with 11 percent. that market signals rather than TLRs are used There were net imports in the Day-Ahead to manage constraints affecting interarea Market at six of PJMs 23 interfaces. The top transactions. Access to the data required for three importing interfaces accounted for 98 understanding loop flow would be a positive percent of the total net imports, PJM/OVEC first step toward economic management of with 72 percent, PJM/New York Independent regional constraints.

System Operator Interface (NYIS) and PJM/

DUK each with 13 percent.

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VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I

Operating Agreements with Bordering The Joint Reliability Coordination Areas. Agreement (JRCA) executed on April 22, 2005, provides for comprehensive reliability PJM and New York Independent System management among the wholesale Operator, Inc. Joint Operating Agreement electricity markets of the Midwest ISO and (JOA).19 On May 22, 2007, the JOA PJM and the service territory of TVA. The between PJM and the New York agreement continued to be in effect Independent System Operator (NYISO) through 2007.

became effective. This agreement was developed to improve reliability. It also PJM and Progress Energy Carolinas, Inc.

formalizes the process of electronic Joint Operating Agreement.22 On checkout of schedules, the exchange of September 9, 2005, the FERC approved a interchange schedules to facilitate JOA between PJM and Progress Energy calculations for available transfer capability Carolinas, Inc. (PEC), with an effective (ATC) and standards for interchange date of July 30, 2005. The agreement revenue metering. This agreement does remained in effect through 2007.

not include provisions for market-based congestion management or other market- PJM and Virginia and Carolinas Area to-market activity. PJM and NYISO should (VACAR) South Reliability Coordination develop market-based congestion Agreement.23 On May 23, 2007, PJM and management protocols as soon as VACAR South (VACAR is a subregion practicable. within the NERC Southeastern Electric Reliability Council (SERC) Region) entered PJM and Midwest ISO Joint Operating into a reliability coordination agreement. It Agreement. The Joint Operating provides for system and outage Agreement between the Midwest coordination, emergency procedures and Independent Transmission System the exchange of data. Provisions are also Operator, Inc. and PJM Interconnection, made for regional studies and L.L.C. continued, in 2007 as in 2006, in recommendations to improve the reliability its second, and final, phase of of interconnected bulk power systems.

implementation including market-to-market activity and coordinated, market-

Interface Pricing Agreements with Individual based congestion management within Companies. PJM entered into locational and between both markets.20 interface pricing agreements with three companies in 2007 that extend the concept of PJM, Midwest ISO and TVA Joint the dynamic scheduling of individual units to Reliability Coordination Agreement.21 entire control areas. These agreements were made available through the PJM website by PJM after a request by the MMU in October.

19 See Joint Operating Agreement Among And Between New York Independent System Operator Inc. And PJM Interconnection, L.L.C. (May 22, 2007) Each of these agreements established a (Accessed January 25, 2008) <http://www.pjm.com/documents/downloads/

agreements/20071102-nyiso-pjm.pdf> (208 KB).

20 See Joint Operating Agreement between the Midwest Independent 22 See Joint Operating Agreement (JOA) between Progress Energy Carolinas, Transmission System Operator, Inc. and PJM Interconnection, L.L.C. (August Inc. and PJM (July 29, 2005) (Accessed February 4, 2008) <http://www.pjm.

24, 2007) (Accessed January 29, 2008) <http://www.pjm.com/documents/ com/documents/ferc/ documents/2005/20050729-er05-___-000.pdf>

downloads/agreements/joa-complete.pdf> (1,662 KB). (2.90 MB).

21 See Joint Reliability Coordination (JRCA) among the Midwest ISO, PJM and 23 See Adjacent Reliability Coordinator Coordination Agreement (May 23, 2007)

TVA (April 22, 2005) (Accessed February 4, 2008) <http://www.pjm.com/ (Accessed February 19, 2008) <http://www.pjm.com/documents/downloads/

documents/downloads/ agreements/20050422-jrca-final.pdf> (145 KB). agreements/executed-pjm-vacar-rc-agreement.pdf> (532 KB).

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report locational price for power sales between PJM total scheduled and actual flows differed by and the individual company that applies under less than 0.5 percent in 2007, greater specified conditions and that differs from the differences existed at individual interfaces.

generally applicable interface price. PJM needs Loop flows are a significant concern because to ensure that such pricing is transparent and they have negative impacts on the efficiency of that all participants have access to the defined market areas with explicit locational pricing, pricing when in the same position. including impacts on locational prices, on FTR revenue adequacy and on system operations,

Consolidated Edison Company of New York, and can be evidence of attempts to game such Inc. (Con Edison) and Public Service Electric markets.

and Gas Company (PSE&G) Wheeling Contracts. During 2007, PJM continued to Loop Flows at the PJM/MECS and PJM/

operate under the terms of the operating TVA Interfaces. As it had in 2006, the protocol that had been developed in 2005.24 All PJM/Michigan Electric Coordinated parties also continued to pursue work on the System (MECS) Interface continued to 19 items identified in the work plan to improve exhibit large imbalances between protocol performance. In August the FERC scheduled and actual power flows, denied a rehearing of Con Edisons complaints particularly during the overnight hours.

regarding protocol performance and refunds.25 The PJM/TVA Interface also exhibited large mismatches between scheduled and

Neptune Underwater Transmission Line to actual power flows, although these Long Island, New York. On July 1, 2007, a 65- mismatches have declined since the mile direct current (DC) transmission line from consolidation of the former PJM southeast Sayreville, New Jersey, to Nassau County on and southwest pricing points in October Long Island, including undersea and 2006. The net difference between underground cable was placed in service. This scheduled flows and actual flows at the is a merchant 230 kV transmission line with a PJM/TVA Interface was imports while the capacity of 660 MW. The line is bi-directional, net difference at the PJM/MECS Interface but in 2007, with the exception of testing, was exports.

power flows were only from PJM to New York.

The average hourly flow for the period July Loop Flows at PJMs Southern Interfaces.

through December was -599 MWh. The improvements in the difference between scheduled and actual power Interchange Transaction Issues flows at PJMs southern interfaces (PJM/

TVA and PJM/Eastern Kentucky Power

Loop Flows. Loop flows are measured as the Corporation (EKPC) to the west and PJM/

difference between actual and scheduled flows eastern portion of Carolina Power & Light at one or more specific interfaces. Loop flows Company (CPLE), PJM/western portion of can arise from transactions scheduled into, out Carolina Power & Light Company (CPLW) of or around the PJM system on contract paths and PJM/DUK to the east) observed at the that do not correspond to the actual physical end of 2006 continued during 2007. In paths that the energy takes. Although PJMs order to reflect the actual flow of transactions associated with the southwest and southeast interface pricing points, on 24 111 FERC ¶ 61,228 (2005).

25 FERC Order Denying Rehearing, Order, Docket No. EL02-23 (August 15, 2007).

October 1, 2006, PJM began to price 20 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I imports and exports differently based on letting the other expire. This rule has not yet their impacts on the PJM transmission been incorporated in PJMs software although system. dispatchers may enforce the rule manually.

Data Required for Full Loop Flow

Spot Import Service. A new interchange Analysis. A complete analysis of loop flow transaction issue emerged in 2007. Some across the Eastern Interconnection could participants obtain and hold large amounts of enhance overall market efficiency, shed spot import service reservations without using light on the interactions among market the service. Prior to April 2007, PJM did not and non market areas and permit market- limit spot import service, preferring to let market based congestion management across prices ration the use of the service which is not the Eastern Interconnection. Loop flows physically limited. PJM interpreted its JOA with have negative impacts on the efficiency of Midwest ISO to require a limitation on spot market prices in markets with explicit import service in order to limit the impact of locational pricing and can be evidence of such transactions on selected external attempts to game such markets. Loop flowgates. The rule caused the availability of flows also have poorly understood impacts spot import service to be limited by ATC on the on non market areas. A complete analysis transmission path. Most of the spot import of loop flow could advance the overall reservations were for monthly service and most transparency of electricity transactions. monthly reservations were not used. Following The data to fully analyze loop flows implementation of the rule, participants have affecting PJM are not currently available to complained that they are not able to obtain this PJM. PJM is presently working with the service. There are a number of possible options North American Electric Reliability Council for addressing the issue including making (NERC) and North American Energy reservations available only hourly or daily or Standards Board (NAESB) to increase requiring reservation holders to release transparency of scheduled and actual reservations if they will not be used within a transactions, generation and loads from defined lead time.

other control areas. This effort should be given a high priority.

Up-to Congestion Transactions. Up-to congestion transactions are Day-Ahead Energy

Ramp Reservation Rule Change. In 2006 the Market transactions for which participants can MMU developed, PJM proposed and the specify the maximum level of positive membership agreed to, changes in the ramp congestion cost that they are willing to pay, up reservation rules that imposed limits on the to a cap of $25 per MWh. There is a mismatch time that a ramp reservation could be held between up-to congestion transactions in the without an associated energy schedule. These Day-Ahead Energy Market and the Real-Time rules showed positive results when they were Energy Market. In the Day-Ahead Energy implemented that were sustained through Market, an up-to congestion import transaction 2007. An additional rule to address artificial is submitted and modeled as an injection at the ramp creation was added in 2007. This rule interface and a withdrawal at a specific PJM sets out the procedure for PJM operators to node. In real time, the power does not flow to follow if they observe a participant who has the PJM node specified in the day-ahead offsetting import and export ramp reservations, transaction. This mismatch results in inaccurate but is only scheduling on one of them while pricing and can provide a gaming opportunity.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Conclusion coordination modeled on the PJM and MISO JOA as soon as possible. The transactions with non Transactions between PJM and multiple control market areas are driven by a mix of incentives areas in the Eastern Interconnection are part of a including market fundamentals but are more difficult single energy market. While some of these control to manage because of the inherent inconsistency areas are termed market areas and some are between the contract path approach taken in non termed non market areas, all electricity transactions market areas and the explicit locational price are part of a single energy market. Nonetheless, approach in market areas. A significant issue is the there are significant differences between market ability of non market transactions to impose and non market areas. Market areas, like PJM, uncompensated costs on market areas in the include essential features such as locational absence of transparency and appropriate market marginal pricing, financial hedging tools (FTRs and signals. The reverse can also occur. For interactions ARRs in PJM) and transparent, least-cost, security- with both market and non market areas, the goal constrained economic dispatch for all available should be to increase the role of market forces generation. Non market areas do not include these consistent with actual power flows and more closely features. The market areas are extremely transparent approach the outcomes and opportunities of a and the non market areas are nontransparent. single, transparent market.

The MMU analyzed the transactions between PJM In order to manage interactions with other market and neighboring control areas for 2007 including areas, PJM has entered into formal agreements evolving transaction patterns, economics and with a number of control areas. The redispatch issues. While PJM market participants historically agreement between PJM and the Midwest ISO is a imported and exported energy primarily in the Real- model for such agreements and is being continuously Time Energy Market, that is no longer the case. improved. As interactions with external areas are PJM continued to be a net exporter of energy and increasingly governed by economic fundamentals, a large share of both import and export activity interface prices and volumes reflect supply and occurred at a small number of interfaces. Three demand conditions and the number of required interfaces accounted for 42 percent of the total interventions in the market has declined, as real-time net exports and two interfaces accounted measured, for example, by the reduction in TLRs for 95 percent of the real-time net import volume. declared by PJM in 2007. However, more needs to Three interfaces accounted for 54 percent of the be done to assure that market signals rather than total day-ahead net exports and three interfaces TLRs are used to manage constraints affecting accounted for 98 percent of the day-ahead net interarea transactions. PJM and NYISO, as import volume. neighboring market areas, should develop market-based congestion management protocols as soon As the data show, there is a substantial level of as practicable. In addition, PJM should continue its transactions between PJM and the contiguous efforts to gain access to the data required to control areas. The transactions with other market understand loop flows in real time and to ensure areas are largely driven by the market fundamentals that responsible parties pay the costs of within each area and between market areas. redispatch.

However, there is room to improve current market-to-market coordination to ensure that these areas In order to manage interactions with non market together more closely approach the outcomes and areas, PJM has entered into coordination opportunities of a single, transparent market. PJM agreements with other control areas as a first step.

and NYISO should implement market-to-market In addition, PJM has attempted to address loop flows by creating and modifying interface prices 22 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I that reflect actual power flows, regardless of areas. PJM and Midwest ISO issued a joint loop contract path. Loop flows are also managed flow report in 2007 that made three recommendations through the use of redispatch and TLR procedures. including the establishment of an energy schedule PJM has entered into dynamic scheduling tag archive. The archive would capture and retain agreements with generation owners for specific data for the entire Eastern Interconnection including units to permit transparent, market-based signals tag impact, generation-to-load impact and market and responses. PJM has modified the rules flow impact data for flowgates in the interchange governing the use of limited transaction ramp distribution calculator (IDC). The archive would be a capability between PJM and contiguous control prime source of information needed to perform areas to help ensure that transactions are free to after-the-fact analyses and reviews. This effort respond to market signals and to reduce the ability should be given a high priority as the data needs to game or hoard ramp. PJM also entered into have been well understood for some time.

agreements with specific control areas for separate interface pricing that have been questioned with PJM needs to continue to pay careful attention to respect to transparency and equal access. PJM all the mechanisms used to manage flows at the needs to ensure that such pricing is transparent interfaces between PJM and surrounding areas.

and that all participants have access to the defined PJM manages its interface with external areas, in pricing when in the same position. part, through limitations on the amount of change in net interchange within 15-minute intervals. The Loop flows are measured as the difference between change in net interchange is referred to as ramp.

actual and scheduled (contract path) flows at one Changes in net interchange affect PJM operations or more specific interfaces. Loop flows do not exist and markets as they require increases or decreases within markets because power flows are explicitly in generation to meet load. As a result of the fact priced under locational marginal pricing, but that ramp is free but is a valuable resource, there markets can create loop flows in external control are strong incentives to game the ramp rules. The areas. PJM attempts to manage loop flows by same is true of spot import service. Up-to congestion creating interface prices that reflect the actual service is a market option used to import power power flows, regardless of contract path. But this into PJM which can create mismatches between approach cannot be completely successful as long transactions in the Day-Ahead Energy Market and as it is possible to schedule a transaction and be the Real-Time Energy Market that result in paid based on that schedule, regardless of how the inaccurate pricing and can provide a gaming power flows. opportunity.

PJM continues to face significant loop flows for Capacity Market reasons that continue not to be fully understood as a result of inadequate access to the required data. Effective June 1, 2007, the PJM Capacity Credit A complete analysis of loop flow across the Eastern Market (CCM), which had been the market design Interconnection could improve overall market since 1999, was replaced with the RPM Capacity efficiency, shed light on the interactions among Market construct. For the 2007 State of the Market market and non market areas and permit market- Report, the Market Monitoring Unit (MMU) analyzed based congestion management across the Eastern the market structure, participant conduct and Interconnection. Loop flows have negative impacts market performance of both Capacity Market on the efficiency of market prices in markets with designs and compared the 2007 market results to explicit locational pricing and can be evidence of 2006 and certain other prior years.

attempts to game such markets. Loop flows also have poorly understood impacts on non market

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Each organization serving PJM load must pay for Market Structure the capacity resources required to meet its capacity obligations. Collectively, all arrangements by which

Supply. Unforced capacity remained relatively load-serving entities (LSEs) acquire capacity are constant in the CCM in January through May known as the Capacity Market.26 Under the CCM, 2007 compared to 2006.29 Average unforced LSEs could acquire capacity resources by relying capacity increased by 377 MW or 0.2 percent on the PJM Capacity Market, by constructing to 152,859 MW. Capacity resources exceeded generation, or by entering into bilateral agreements. capacity obligations every day by an average Under RPM, LSEs must pay the locational capacity of 9,450 MW, a decrease of 81 MW from the price for their zone. LSEs can own capacity or average net excess of 9,531 MW for 2006.

purchase capacity bilaterally and can offer capacity into the RPM Auctions.

Demand. Unforced obligations also remained relatively constant in the PJM CCM in January The MMU analyzed market structure and market through May 2007 compared to 2006. Average performance in the PJM Capacity Market for load obligations increased by 458 MW or 0.3 calendar year 2007, including supply, demand, percent to 143,409 MW. PJM electricity concentration ratios, pivotal suppliers, volumes, distribution companies (EDCs) and their prices, outage rates and reliability. The analyses of affiliates maintained an 80.8 percent market the two market designs are presented separately, share of load obligations in the PJM CCM in but there is substantial overlap in the basic elements January through May 2007, down from 87.6 of the Capacity Markets. percent for 2006. (See Figure 15.)

Capacity Credit Market Figure 15 PJM Capacity Market load obligation served (Percent): January through May 2007 Market Design 100% PJM EDC PJM EDC generating affiliate 90% PJM EDC marketing affiliate The PJM CCM provided mechanisms to balance 80%

Non-PJM EDC generating affiliate Non-PJM EDC marketing affiliate Non-EDC generating affiliate the supply of and demand for capacity unmet by 70% Non-EDC marketing affiliate Load obligation served the bilateral market or self-supply.27 The CCM 60%

consisted of the Daily, Interval, Monthly and 50%

40%

Multimonthly CCM.28 The CCM was intended to 30%

provide a transparent, market-based mechanism 20%

for retail LSEs to acquire the capacity resources 10%

needed to meet their capacity obligations and to 0%

Jan Feb Mar Apr May sell capacity resources when no longer needed to serve load. The Daily CCM permitted LSEs to match capacity resources with short-term shifts in retail

Market Concentration. Structural analysis of load while the Interval, Monthly and Multimonthly the PJM Capacity Market during the January CCMs provided mechanisms to match longer-term through May period found significant market obligations to serve load with capacity resources. structure issues both in the CCM and the overall ownership of capacity. All daily auctions 26 See the 2007 State of the Market Report, Volume II, Appendix M, Glossary and failed the three pivotal supplier (TPS) test; 97.4 Appendix N, Acronyms for definitions of PJM Capacity Market terms.

27 All PJM Capacity Market values (capacities) are in terms of unforced MW.

28 PJM defined three intervals for its CCM. The first interval extended for five months and ran from January through May. The second interval extended for 29 For information on the CCM during 2006, see the 2006 State of the Market four months and ran from June through September. The third interval extended Report, Volume II, Section 5, Capacity Market.

for three months and ran from October through December.

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VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I percent of daily auctions failed the single pivotal Figure 16 PJM Daily and Monthly/Multimonthly CCM supplier test and 83.3 percent of monthly performance: June 1999 through May 2007 auctions failed the single pivotal supplier test.

Daily CCM Total capacity ownership also failed the single 10,000 Monthly/Multimonthly CCM $250 Weighted-average capacity clearing price ($/MW-day): Lines Daily weighted-average price Average daily capacity credits (Unforced MW): Bars 9,000 pivotal supplier test throughout the period, with 8,000 Monthly/Multimonthly weighted-average price

$200 three individual suppliers who were each pivotal 7,000 on a stand-alone basis. 6,000 $150 5,000 4,000 $100

Imports and Exports. In January through May 3,000 2,000 $50 2007, imports averaged 2,794 MW, which was 1,000 a decrease of 299 MW or 9.7 percent from the 0 Jun-99 Sep-99 Dec-99 Mar-00 Jun-00

$0 2006 average of 3,093 MW. Exports averaged Sep-00 Dec-00 Mar-01 Jun-01 Sep-01 Dec-01 Mar-02 Jun-02 Sep-02 Dec-02 Mar-03 Jun-03 Sep-03 Dec-03 Mar-04 Jun-04 Sep-04 Dec-04 Mar-05 Jun-05 Sep-05 Dec-05 Mar-06 Jun-06 Sep-06 Dec-06 Mar-07 4,939 MW, which was a decrease of 19 MW or 0.4 percent from the 2006 average of 4,958 MW. Average net exchange increased by 280 RPM Capacity Market MW or 15.0 percent to -2,145 MW from the 2006 average of -1,865 MW. Internal bilateral Market Design transactions averaged 163,009 MW, which was an increase of 2,057 MW or 1.3 percent On June 1, 2007, the RPM Capacity Market design from the 160,952 MW average for 2006. was implemented in the PJM region, replacing the CCM Capacity Market design that had been in

Active Load Management (ALM). In January place since 1999.30 The RPM market design differs through May 2007, ALM credits in the PJM from the CCM market design in a number of CCM averaged 1,677 MW, down 151 MW (8.3 important ways. The RPM is a forward-looking, percent) from 1,828 MW in 2006. annual, locational market, with a must-offer requirement for capacity and mandatory Market Performance participation by load, with performance incentives for generation, that includes clear, market power

CCM Prices and Volumes. During January mitigation rules and that permits the direct through May 2007, total PJM CCM prices participation of demand-side resources. CCM, in averaged $3.21 per MW-day, which was $2.52 contrast, was a daily, single-price, voluntary per MW-day less than the 2006 average of balancing market that included less than 10 percent

$5.73 per MW-day. Total PJM CCM transactions of total PJM capacity, that had weak performance averaged 11,727 MW (8.2 percent of obligation), incentives, that had no explicit market power 2,609 MW higher than the 2006 average of mitigation rules and that did not permit the 9,118 MW (6.4 percent of obligation). participation of demand-side resources.

For calendar year 2006, capacity resources Under RPM, capacity obligations are annual. Under across the entire regional transmission CCM, capacity obligations were daily. Under RPM, organization (RTO) were valued at a total of auctions are held for delivery years that are three

$299.0 million. This equals the total capacity years in the future. Under CCM daily, monthly and obligation valued at the combined-market, multimonthly auctions were held. Under RPM, weighted-average CCM clearing price for 2006. 30 The terms PJM Region, RTO Region and RTO are synonymous in the 2007 State of the Market Report, Volume II, Section 5, Capacity Market and include all capacity within the PJM footprint.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report prices are locational and may vary depending on was defined by participant buy bids. Under RPM transmission constraints.31 Under CCM, prices there are performance incentives for generation.

were the same, regardless of location. Under RPM, Under CCM the only performance incentive was sell offers are unit-specific. Under CCM, offers were the direct relationship between historical equivalent non-unit-specific capacity credits. Under RPM, demand forced outage rate (EFORd) and the existing generation capable of qualifying as a amount of capacity that could be sold.

capacity resource must be offered into RPM Auctions, except for the fixed resource requirement Under RPM there are explicit market power (FRR) option. Under CCM, there was no must-offer mitigation rules that define structural market power, rule after June 2000. Under RPM, participation by that define offer caps based on the marginal cost of LSEs is mandatory, except for the FRR option. capacity and that do not limit prices offered by new Under CCM, there was no mandatory participation entrants. Under CCM, there were no explicit market in the CCM auctions.32 Under RPM, there is an power mitigation rules. Under RPM, demand-side administratively determined demand curve that resources may be offered directly into the auctions defines scarcity pricing levels and that, with the and receive the clearing price. Under CCM, supply curve derived from capacity offers, demand-side resources could not be offered directly determines market prices. Under CCM the demand into the market.

Table 15 PJM capacity summary (MW): January 1, 2007, through June 1, 2009 01-Jan-07 31-May-07 01-Jun-07 01-Jun-08 01-Jun-09 Installed capacity (ICAP) 162,840.7 162,036.6 163,721.1 164,444.1 166,916.0 Unforced capacity (pre-RPM) A 153,148.6 152,714.3 154,076.7 155,590.2 157,628.7 Cleared capacity B 129,409.2 129,597.6 132,231.8 Obligation/RPM reliability requirement (pre-FRR) C 142,978.7 143,780.2 148,277.3 150,934.6 153,480.1 Obligation/RPM reliability requirement (less FRR) D 125,805.0 128,194.6 130,447.8 Net excess (pre-RPM) A-C 10,169.9 8,934.1 5,799.4 4,655.6 4,148.6 Net excess (RPM) B-D+E-F 5,240.5 3,066.6 3,445.7 Imports 2,784.5 2,784.6 2,809.2 2,460.3 2,505.4 Exports (4,621.4) (5,038.0) (3,938.5) (3,838.1) (2,194.9)

Net exchange (1,836.9) (2,253.4) (1,129.3) (1,377.8) 310.5 ALM 1,676.7 1,676.7 DR cleared 127.6 536.2 892.9 ILR E 1,636.3 2,109.9 2,107.5 FRR DR F 446.3 445.8 HHI 911 895 895 879 853 Highest market share 16.2% 16.7% 16.0% 18.5% 18.4%

RSI3 0.59 0.61 0.59 0.61 0.60 Pivotal suppliers 1 1 1 1 1 31 Transmission constraints are local capacity import capability limitations (low capacity emergency transfer limit (CETL) margin over capacity emergency transfer objective (CETO)) caused by transmission facility limitations, voltage limitations or stability limitations.

32 See Reliability Assurance Agreement among Load-Serving Entities in the PJM Region, Schedule 8.1 (June 1, 2007) (Accessed July 19, 2007) <http://www.

pjm.com/documents/ downloads/agreements/raa.pdf> (1.92 MB).

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VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I Market Structure

Demand. There was a 5,298.6 MW increase in the RPM reliability requirement, which is similar

Supply. Total internal capacity increased from to the obligation under CCM, from 142,978.7 154,985.5 MW on January 1, 2007, to MW on January 1, 2007, to 148,277.3 MW on 155,206.0 MW on June 1, 2007, or 220.5 MW. June 1, 2007. On June 1, 2007, PJM EDCs This increase was the result of 573.2 MW from and their affiliates maintained a 77.5 percent demand response (DR) offered into the auction, market share of load obligations under RPM, offset in part by 332.6 MW from higher EFORds down from an average of 80.8 percent for the and 20.1 MW from generation deratings. No first five months of 2007 under CCM.

new generation was offered into the 2007/2008 RPM Auction.

Market Concentration. For the 2007/2008, 2008/2009 and 2009/2010 RPM Auctions, all In the 2008/2009 and 2009/2010 auctions, defined markets failed the preliminary market new generation increased 528.6 MW; 112.6 structure screen (PMSS). In each auction all MW were brought out of retirement and net participants in the total PJM market as well as the generation uprates were 220.3 MW, for a total locational deliverability area (LDA) markets failed of 861.5 MW. DR offers increased 815.9 MW the three pivotal supplier (TPS) market structure through June 1, 2009. Net improvements in test. The result was that offer caps were applied EFORds added 434.8 MW. The net effect from to all sell offers in all three auctions.

May 31, 2007, through June 1, 2009, was an increase in total internal capacity of 2,350.6

Imports and Exports. Net exchange, which is MW (1.5 percent) from 154,967.6 MW to imports less exports, decreased 707.6 MW 157,318.2 MW. from January 1, to June 1, 2007, as the result of a decrease in exports of 682.9 MW and an In the 2008/2009 auction, 15 more generating increase in imports of 24.7 MW.

units made offers than in the 2007/2008 RPM Auction. The increase included five new wind

Demand-Side Resources. Under RPM, units (66.1 MW), three new diesel units (23.3 demand-side resources in the Capacity Market, MW) and two units (112.6 MW) which came a combination of DR offered into the RPM out of retirement while the remaining five units Auctions and certified/forecast interruptible were the result of a reclassification of external load for reliability (ILR), increased from the units. 1,676.7 MW in the CCM ALM program by 87.2 MW on June 1, 2007, by an additional 882.2 In the 2009/2010 auction, 17 more generating MW on June 1, 2008, and an additional 354.3 units made offers than in the 2008/2009 RPM MW on June 1, 2009. The ALM volumes were Auction. The increase included eight new MW credits against the obligation while the LM combustion turbine (CT) units (380.2 MW), two volumes are treated as capacity resources.

new diesel units (9.2 MW) and one new steam unit (49.8 MW) while the remaining six units

Net Excess. Net excess as calculated under included more units imported, fewer units CCM decreased 4,370.5 MW from 10,169.9 exported, a decrease in units excused from MW on January 1, to 5,799.4 MW on June 1, offering into the auction and fewer units 2007. Net excess as calculated under RPM removed from the auction under the fixed was 5,240.5 MW or 558.9 MW less than the resource requirement (FRR) option. 5,799.4 MW as calculated under CCM on June 1, 2007.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Market Conduct of 19.8 percent, which was 3,604.2 MW greater than the reliability requirement of

2007/2008 RPM Auction. Of the 1,061 125,805.0 MW (installed reserve margin (IRM) generating units which submitted offers, unit- of 15.0 percent) and resulted in a clearing price specific offer caps were calculated for 125 of $40.80 per MW-day.

units (11.8 percent). Offer caps of all kinds were used by 566 units (53.4 percent), of which Total resources in the RTO were 129,409.2 388 were the default (proxy) offer caps MW which resulted in a net excess of 5,240.5 calculated and posted by the MMU. The MW, a decrease of 3,693.6 MW from the net remaining 495 units were price takers, of which excess of 8,934.1 MW on May 31, 2007.

the offers for 492 units were zero and the offers Certified interruptible load for reliability (ILR) for three units were set to zero because no was 1,636.3 MW.

data were submitted. Fifteen DR resources offered into the auction. Cleared resources across the entire RTO will receive a total of $4.3 billion based on the

2008/2009 RPM Auction. Of the 1,076 unforced MW cleared and the prices in the generating units which submitted offers, unit- 2007/2008 RPM Auction.

specific offer caps were calculated for 117 units (10.9 percent). Offer caps of all kinds

Eastern Mid-Atlantic Area Council (EMAAC).

were used by 567 units (52.7 percent), of which Total internal EMAAC unforced capacity of 399 were the default (proxy) offer caps 30,825.1 MW includes all generating units and calculated and posted by the MMU. DR that qualified as a PJM capacity resource, excludes external units and reflects owners

2009/2010 RPM Auction. Of the 1,093 modifications to ICAP ratings. Including imports generating units which submitted offers, unit- into EMAAC, RPM unforced capacity was specific offer caps were calculated for 151 30,841.0 MW. Of the 2,121.8 MW of incremental units (13.8 percent). Offer caps of all kinds supply, 2,092.4 MW cleared, which resulted in a were used by 550 units (50.3 percent), of which resource-clearing price of $197.67 per MW-day.

377 were the default (proxy) offer caps calculated and posted by the MMU. Total resources in EMAAC were 36,642.8 MW, which when combined with certified ILR of Market Performance 387.0 MW resulted in a net excess of -206.9 MW (0.6 percent) less than the reliability 2007/2008 RPM Auction requirement of 37,236.7 MW.

RTO. Total internal RTO unforced capacity of

Southwestern Mid-Atlantic Area Council 155,206.0 MW includes all generating units (SWMAAC). Total internal SWMAAC unforced and DR that qualified as a PJM capacity capacity of 10,352.2 MW includes all generating resource for the 2007/2008 RPM Auction, units and DR that qualified as a PJM capacity excludes external units and reflects owners resource, excludes external units and reflects modifications to installed capacity (ICAP) owners modifications to ICAP ratings. There ratings. Including FRR, committed resources were no imports from outside PJM into and imports, RPM capacity was 135,092.6 SWMAAC. All of the 650.1 MW of incremental MW. The 129,409.2 MW of cleared resources supply cleared, resulting in a resource-clearing for the entire RTO represented a reserve margin price of $188.54 per MW-day.

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VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I Total resources in SWMAAC were 15,900.2 performance incentives for generation, that includes MW, which when combined with certified ILR clear, market power mitigation rules and that of 273.4 MW resulted in a net excess of 98.3 permits the direct participation of demand-side MW (0.6 percent) greater than the reliability resources.

requirement of 16,075.3 MW.

The RPM Capacity Market design explicitly Generator Performance addresses the underlying issues of ensuring that competitive prices can reflect local scarcity while

Forced Outage Rates. From 2003 to 2004, not relying on the exercise of market power to the average PJM EFORd increased, from 6.7 achieve the design objective and explicitly limiting percent in 2003 to 7.3 percent in 2004.33 In the exercise of market power.

2005, the average PJM EFORd decreased to 6.6 percent, continued to decrease in 2006 to The Capacity Market is, by design, always tight in 6.4 percent and then increased to 6.9 percent the sense that total supply is generally only slightly in 2007. The increase in EFORd from 2006 to larger than demand. This is the case for the CCM 2007 was the result of increased forced outage design as well as for the RPM. The demand for rates of combustion turbine and steam capacity includes expected peak load plus a reserve generating unit types. These forced outage margin. Thus, the reliability goal is to have total rates are for the entire PJM Control Area.34 supply equal to, or slightly above, the demand for capacity. The market may be long at times, but that Figure 17 Trends in the PJM equivalent demand forced is not the equilibrium state. Capacity in excess of outage rate (EFORd): Calendar years 2003 to 2007 35 demand is not sold and, if it does not earn adequate revenues in other markets, will retire. Demand is 8%

almost entirely inelastic because the market rules require loads to purchase their share of the system 7%

capacity requirement. The result is that any supplier that owns more capacity than the difference 6% between total supply and the defined demand is pivotal and has market power.

5%

2003 2004 2005 2006 2007 In other words, the market design for capacity leads, almost unavoidably, to structural market Conclusion power. Given the basic features of market structure in the PJM Capacity Market, including significant The RPM Capacity Market design was implemented market structure issues, inelastic demand, tight effective June 1, 2007. RPM represents a significant supply-demand conditions, the relatively small change in the structure of the Capacity Market in number of nonaffiliated LSEs and supplier PJM. The RPM is a forward-looking, annual, knowledge of aggregate market demand, the MMU locational market, with a must-offer requirement for concludes that the potential for the exercise of capacity and mandatory participation by load, with market power continues to be high. Market power is and will remain endemic to the existing structure of the PJM Capacity Market. This is not surprising 33 Annual EFORd data presented in state of the market reports may be revised based on final data submitted after the publication of the reports. in that the Capacity Market is the result of a 34 In some cases, data for the AEP, DAY, DLCO, Dominion and ComEd control zones may be incomplete for the years 2002 and 2003. Only data that have regulatory/administrative decision to require a been reported to PJM were used. specified level of reliability and the related decision 35 Data for 2003 are incomplete for some units in newly integrated areas.

Available information supports the conclusion that there is no significant impact on the results of the analysis.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report to require all load-serving entities to purchase a Generators want to maximize their sales of energy share of the capacity required to provide that when prices are high and if they are successful, this reliability. It is important to keep these basic facts in will also result in lower forced outage rates. Well-mind when designing and evaluating capacity designed scarcity pricing could also provide strong, markets. The Capacity Market is unlikely ever to complementary incentives for reduced outages approach the economists view of a competitive during high-load periods. It would be preferable to market structure in the absence of a substantial rely on strong market-based incentives for capacity and unlikely structural change that results in much resource performance rather than the current more diversity of ownership. structure of penalties, which has its own incentive effects.

The RPM Capacity Market design represents a significant advance over the previous CCM design The analysis of PJM Capacity Markets begins with in ensuring competitive outcomes because RPM market structure, which provides the framework for has explicit market power mitigation rules designed the actual behavior or conduct of market to permit competitive, locational capacity prices participants. The analysis also examines participant while limiting the exercise of market power. The behavior in the context of market structure. In a RPM construct is consistent with the appropriate competitive market structure, market participants market design objectives of permitting competitive are constrained to behave competitively. In a prices to reflect local scarcity conditions while competitive market structure, competitive behavior explicitly limiting market power. The RPM Capacity is profit-maximizing behavior. Finally, the analysis Market design provides that competitive prices can examines market performance results. The actual reflect locational scarcity while not relying on the performance of the market, measured by price and exercise of market power to achieve that design the relationship between price and marginal cost, objective and limits the exercise of market power results from the interaction of these elements.

via the application of the three pivotal supplier test.

The MMU found serious market structure issues, The introduction of the RPM design had a large but no exercise of market power in the PJM impact on total capacity-related revenues. Under Capacity Market. The behavior of market participants the CCM design, for calendar year 2006, capacity in the context of the market structure and the supply resources across the entire RTO were valued at a and demand fundamentals offset these market total of $299.0 million. Under the RPM, cleared structure issues in the PJM Capacity Market under capacity resources across the entire RTO, were the CCM construct in 2007. Explicit market power valued at $4.3 billion under the 2007/2008 auction, mitigation rules in the RPM construct offset the an increase of approximately $4 billion. underlying market structure issues in the PJM Capacity Market under RPM. The PJM Capacity The existence of a Capacity Market that links Market results were competitive during 2007.

payments for capacity to the level of unforced capacity and therefore to the forced outage rate Ancillary Service Markets creates an incentive to improve forced outage rates.

These incentives were somewhat attenuated in the The FERC defined six ancillary services in Order CCM design. The performance incentives are 888: 1) scheduling, system control and dispatch; 2) stronger in the RPM Capacity Market design reactive supply and voltage control from generation although they need further strengthening. The service; 3) regulation and frequency response Energy Market also provides incentives for improved service; 4) energy imbalance service; 5) operating performance with somewhat different characteristics. reserve - synchronized reserve service; and 6) 30 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I operating reserve - supplemental reserve service.36 requirements and scheduling. Generation owners Of these, PJM currently provides regulation, energy are paid according to the FERC-approved, reactive imbalance and synchronized reserve services revenue requirements. Charges are allocated to through market-based mechanisms. PJM provides network customers based on their percentage of energy imbalance service through the Real-Time load, as well as to point-to-point customers based Energy Market. PJM provides the remaining ancillary on their monthly peak usage.

services on a cost basis.

The MMU analyzed measures of market structure, Regulation matches generation with very short- conduct and performance of the PJM Regulation term changes in load by moving the output of Market and of its two Synchronized Reserve selected generators up and down via an automatic Markets for 2007, comparing market results to control signal.37 Regulation is provided, independent 2006 and to certain other prior years.

of economic signal, by generators with a short-term response capability (i.e., less than five minutes) or Regulation Market by DSR. Longer-term deviations between system load and generation are met via primary and On August 1, 2005, PJM integrated what had been secondary reserve and generation responses to five regulation control zones into one combined economic signals. Synchronized reserve is a form Regulation Market for a trial period. After the trial of primary reserve. To provide synchronized reserve period and after a report by the MMU, PJM a generator must be synchronized to the system stakeholders will vote on whether to keep the and capable of providing output within 10 minutes. combined market. The MMU provided that report Synchronized reserve can also be provided by on October 18, 2006, and the issue is still under DSR. The term, Synchronized Reserve Market, review by PJM members.38 Both the 2006 State of refers only to supply of and demand for Tier 2 the Market Report and the 2007 State of the Market synchronized reserve. Report have updated the analysis presented in that report.

Both the Regulation and Synchronized Reserve Markets are cleared on a real-time basis. A unit can Market Structure be selected for either regulation or synchronized reserve, but not for both. The Regulation and the

Supply. During 2007, the supply of offered and Synchronized Reserve Markets are cleared eligible regulation in PJM was generally both interactively with the Energy Market and operating stable and adequate. Although PJM rules allow reserve requirements to minimize the cost of the up to 25 percent of the regulation requirement combined products, subject to reactive limits, to be satisfied by demand resources, none resource constraints, unscheduled power flows, qualified to make regulation offers in 2007. The interarea transfer limits, resource distribution ratio of eligible regulation offered to regulation factors, self-scheduled resources, limited fuel required averaged 1.90 throughout 2007.

resources, bilateral transactions, hydrological constraints, generation requirements and reserve

Demand. PJM calculates the regulation requirements. requirement each day for the entire day using 1.0 percent of the forecast-peak load for its PJM does not provide a market for reactive power, control area. This requirement was established but does ensure its adequacy through member in August 2006. Because it is a function of 36 75 FERC ¶ 61,080 (1996). 38 See Market Monitoring Unit. Analysis of the Combined Regulation Market:

August 1, 2005 through July 31, 2006 (October 18, 2006) <http://www.

37 Regulation is used to help control the area control error (ACE). See 2007 State pjm.com/markets/market-monitor/downloads/mmu-reports/20061018-mmu-of the Market Report, Volume II, Appendix F, Ancillary Service Markets, for a regulation-market-report.pdf> (76.1 KB).

full definition and discussion of ACE.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report peak load, the regulation requirement is average price for regulation during 2006. In seasonal. The average hourly regulation 2007, based on MMU estimates of the marginal demand in 2007 was 967 MW. For the winter cost of regulation, offers at levels greater than the demand was 956 MW; for the spring it was competitive levels set the clearing price for 913 MW; for the summer it was 1,089 MW; regulation in about 26 percent of all hours.

and for the fall it was 911 MW.

Figure 18 Monthly average regulation demand

Market Concentration. During 2007, the PJM (required) vs. price: Calendar year 2007 Regulation Market had a load-weighted, 1,400 $60 Regulation required average Herfindahl-Hirschman Index (HHI) of Regulation market-clearing price 1,200 1281 which is classified as moderately $50 concentrated.39 The minimum hourly HHI was 1,000

$40 720 and the maximum hourly HHI was 2547. 800 The largest hourly market share in any single MW $30 Price 600 hour0.00694 days 0.167 hours 9.920635e-4 weeks 2.283e-4 months was 43 percent, and 56 percent of all

$20 hours had a maximum market share greater 400 than 20 percent. In 2007, 80 percent of hours 200

$10 had three or fewer pivotal suppliers. The MMU 0 $0 concludes from these results that the PJM Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Regulation Market in 2007 was characterized by structural market power in 80 percent of the Synchronized Reserve Market hours.

In February 2007, PJM restructured the Market Conduct Synchronized Reserve Market.40 Throughout 2006 and for January 2007, PJM had four zonal

Offers. The offer price is provided by the unit Synchronized Reserve Markets: the PJM Mid-owner, is applicable for the entire operating day Atlantic Region, the ComEd Control Zone, the PJM and, with lost opportunity cost (LOC), Western Region and the PJM Southern Region. On comprises the total offer to the Regulation February 1, 2007, the PJM Mid-Atlantic Region, the Market. The regulation offer price is subject to ComEd Control Zone and the PJM Western Region a $100-per-MWh offer cap, with the exception were combined into one market called the RFC of the two dominant suppliers, whose offers Synchronized Reserve Zone. The PJM Southern are capped at marginal cost plus $7.50 per Region became the Southern Synchronized MWh plus LOC. All suppliers are paid the Reserve Zone. The RFC Synchronized Reserve market-clearing price. Zone is governed by the reliability requirements of the ReliabilityFirst Corporation. The Southern Market Performance Synchronized Reserve Zone (Dominion) reliability requirements are set by the Southeastern Electric

Price. For the PJM Regulation Market during Reliability Council (SERC).

2007 the load-weighted, average price per MWh (i.e., the regulation market-clearing price, Market Structure including LOC) associated with meeting PJMs demand for regulation was $36.86. This

Supply. During January 2007, the offered and represents an increase of $4.17 from the eligible excess supply ratio was 1.28 for the 39 See the 2007 State of the Market Report, Volume II, Section 2, Energy 40 In PJM, the term, Synchronized Reserve Market, is used to refer only to Tier 2 Market, Part I, at Market Concentration for a more complete discussion of synchronized reserve.

concentration ratios and the Herfindahl-Hirschman Index (HHI).

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I PJM Mid-Atlantic Synchronized Reserve requirements. Market demand is less than the Region and the ratio was 1.24 for the ComEd requirement by the amount of Tier 1 Synchronized Reserve Control Zone.41 During synchronized reserve available at the time a February to December 2007, the offered and Synchronized Reserve Market is cleared. The eligible excess supply ratio was 1.81 for the average demand for Tier 2 synchronized RFC Synchronized Reserve Zone and the ratio reserve in the Mid-Atlantic Subzone of the RFC was 1.25 for the Mid-Atlantic Subzone of the Synchronized Reserve Zone was 184 MW. The RFC Synchronized Reserve Zone. These average demand for Tier 2 synchronized excess supply ratios are determined using the reserve in the Southern Synchronized Reserve administratively required synchronized reserve. Zone was 4 MW.

The actual requirement for Tier 2 synchronized reserve is lower because there is usually a Figure 110 RFC Synchronized Reserve Zone, Mid-significant amount of Tier 1 synchronized Atlantic Subzone synchronized reserve required vs.

reserve available. In August 2006, DSR scheduled: February through December 2007 resources began participating in PJM Scheduled MW Synchronized Reserve Markets. As of the end 1,400 Required MW of 2007, the MW contribution of DSR resources 1,200 to the Synchronized Reserve Market had 1,000 become significant. (See Figure 19.)

800 MW Figure 19 PJM RFC Zone Tier 2 synchronized reserve 600 scheduled MW: February through December 2007 400 180,000 Scheduled MW DSR MW 200 160,000 140,000 0 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 120,000 100,000 MW 80,000

Market Concentration. In 2007, market 60,000 concentration was high in the Tier 2 40,000 Synchronized Reserve Markets. The average 20,000 cleared Synchronized Reserve Market HHI for the Mid-Atlantic Subzone of the RFC 0

Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Synchronized Reserve Zone throughout 2007 was 4151. The largest hourly market share was 100 percent and 76 percent of all hours

Demand. The average synchronized reserve had a maximum market share greater than 40 requirements were: 1,300 MW for the RFC percent. In the Mid-Atlantic Subzone of the Synchronized Reserve Zone and 1,160 MW for RFC Synchronized Reserve Market, in 2007, the Mid-Atlantic Subzone. For the Southern 58 percent of hours had three or fewer pivotal Synchronized Reserve Zone, the requirement suppliers. The MMU concludes from these was usually 0 MW. These requirements are a results that the PJM Synchronized Reserve function of administratively determined, regional Markets in 2007 were characterized by structural market power.

41 The Synchronized Reserve Markets in the Western Region and the Southern Region cleared in so few hours that related data for those markets are not meaningful.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report Market Conduct Markets in August 2006. Participation of demand response grew significantly in 2007.

Offers. The offer price is provided by the unit Not only did more participants offer DSR, but owner, is applicable for the entire operating day demand response was generally less expensive and, with lost opportunity cost calculated by than other forms of synchronized reserve. In 19 PJM, comprises the merit-order price to the percent of hours during 2007 in which a Tier 2 Synchronized Reserve Market. The Synchronized Reserve Market was cleared for synchronized reserve offer made by the unit the Mid-Atlantic Subzone, all synchronized owner is subject to an offer cap of marginal reserve was provided by DSR.

cost plus $7.50 per MWh, plus lost opportunity cost. All suppliers are paid the higher of the

Availability. A synchronized reserve deficit market-clearing price or their offer plus their occurs when the combination of Tier 1 and Tier unit-specific opportunity cost. 2 synchronized reserve is not adequate to meet the synchronized reserve requirement.

Market Performance Neither PJM Synchronized Reserve Market experienced deficits during 2007.

Price. The load-weighted, average PJM price for Tier 2 synchronized reserve in the Mid- Conclusion Atlantic Subzone of the RFC Synchronized Reserve Market was $16.28 per MW in 2007, PJM consolidated its Regulation Markets into a a $1.71 per MW increase from 2006. single Combined Regulation Market, on a trial basis, effective August 1, 2005. The MMU has consistently

Price and Cost. There was a significant change found since that time that the PJM Regulation in the operation of the Synchronized Reserve Market is characterized by structural market power.

Market in the last quarter of 2007 as PJM relied This conclusion is based on the results of the three less on the market and more on out-of-market pivotal supplier test. In addition, in 2007, as in 2006, purchases of spinning reserve for local needs. the MMU cannot conclude that the Regulation The increase in out-of-market purchases Market produced competitive results or indicates that the Synchronized Reserve noncompetitive results, based on the MMU analysis Market is not functioning to coordinate supply of the relationship between the offer prices and and demand. It is not clear why the additional marginal costs of units that set the price in the synchronized reserve requirements cannot be Regulation Market, the marginal units. The MMUs procured via the market. If these requirements reliance on estimates of regulation costs is one of cannot be procured via the market, it is not the reasons that the MMU recommends that all clear why the out-of-market purchase of suppliers be required to provide cost-based spinning reserve resources for local issues regulation offers as part of real-time market power should not be treated as operating reserve mitigation.

charges. While the creation of the Synchronized Reserve Market for the entire RFC Zone The MMU has also consistently concluded that suggested that there is a single, geographic PJMs consolidation of its Regulation Markets had market, the actual results are not consistent resulted in improved performance and in increased with that view. competition compared to the PJM Mid-Atlantic Regulation Market or the Western Region Regulation

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I Market on a stand-alone basis.42, 43 This conclusion two dominant suppliers may have structural market holds true for the 2007 Regulation Market. The power that requires mitigation. The MMU also combined market results include the effects of the recommends that the overall $100 regulation offer current mitigation mechanism which offer caps the cap remain in effect. The retention of an overall offer two dominant suppliers in every hour. The MMU cap together with a real-time, three pivotal supplier concludes that it would be preferable to retain the test for market structure is identical to PJMs current existing, single PJM Regulation Market as the long- practice in the Energy Market.

term market if appropriate mitigation can be implemented that addresses only the hours in The structure of each Synchronized Reserve Market which structural market power exists and which, has been evaluated and the MMU has concluded therefore, provides an incentive for the continued that these markets are not structurally competitive development of competition. as they are characterized by high levels of supplier concentration and inelastic demand. (The term, With respect to mitigation, the MMU recommends Synchronized Reserve Market, refers only to Tier 2 that real-time, hourly market structure tests be synchronized reserve.) As a result, these markets implemented in the Regulation Market, that market are operated as markets with market-clearing power mitigation be applied only for hours in which prices and with offers based on the marginal cost of the market structure is noncompetitive and that producing the service plus a margin. As a result of market power mitigation be applied only to the these requirements, the conduct of market companies failing the market structure tests. More participants within these market structures has specifically, the MMU recommends that the three been consistent with competition, and the market pivotal supplier test be applied hourly in the performance results have been competitive. Prices Regulation Market using a market definition of all for synchronized reserve in the RFC Synchronized eligible offers less than, or equal to, 1.50 times the Reserve Zone and in the Southern Synchronized clearing price and that mitigation be applied to only Reserve Zone are market-clearing prices determined those regulation-owning companies that fail the by the supply curve and the administratively defined test in that hour.44 demand. The cost-based synchronized reserve offers are defined to be the unit-specific incremental This more flexible and real-time approach to cost of providing synchronized reserve plus a mitigation represents an improvement over the margin of $7.50 per MWh plus lost opportunity cost current approach to mitigation which requires cost- calculated by PJM.

based offers from the two dominant companies at all times. The proposed approach to mitigation also There was a significant change in the operation of represents an improvement over prior methods of the Synchronized Reserve Market in the last quarter simply defining the market to be noncompetitive of 2007 as PJM relied less on the market and more and limiting all offers to cost-based offers. The real- on out-of-market purchases of spinning reserve for time approach recognizes that at times the market local needs. Beginning in October and increasing is structurally competitive and therefore no mitigation substantially in November and December, there is required; that at times the market is not structurally was an increase in the amount of combustion-competitive and mitigation is required; and that at turbine-based, synchronized condenser MW added times generation owners other than the designated, by PJM market operations to the Synchronized Reserve Market after market clearing. MW added 42 2005 State of the Market Report (March 8, 2006), pp. 260-263. after the market cleared accounted for more than 43 2006 State of the Market Report (March 8, 2007), p. 247. 50 percent of total synchronized reserve MW 44 See the 2007 State of the Market Report, Volume II, Appendix L, Three Pivotal Supplier Test.

purchased in December.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report The increase in out-of-market purchases indicates Congestion that the Synchronized Reserve Market is not functioning to coordinate supply and demand. It is Congestion occurs when available, least-cost not clear why the additional synchronized reserve energy cannot be delivered to all loads for a period requirements cannot be procured via the market. If because transmission facilities are not adequate to these requirements cannot be procured via the deliver that energy to some loads. When the least-market, it is not clear why the out-of-market cost available energy cannot be delivered to load in purchase of spinning reserve resources for local a transmission-constrained area, higher cost units issues should not be treated as operating reserve in the constrained area must be dispatched to meet charges. While the creation of the Synchronized that load.45 The result is that the price of energy in Reserve Market for the entire RFC Zone suggested the constrained area is higher than in the that there is a single, geographic market, the actual unconstrained area because of the combination of results are not consistent with that view. transmission limitations and the cost of local generation. LMPs reflect the price of the lowest-The benefits of markets are realized under these cost resources available to meet loads, taking into approaches to ancillary service markets. Even in account actual delivery constraints imposed by the the presence of structurally noncompetitive transmission system. Thus LMP is an efficient way markets, there can be transparent, market-clearing to price energy when transmission constraints exist.

prices based on competitive offers that account Congestion reflects this efficient pricing.

explicitly and accurately for opportunity cost. This is consistent with the market design goal of ensuring Congestion reflects the underlying features of the competitive outcomes that provide appropriate power system including the nature and capability of incentives without reliance on the exercise of market transmission facilities and the cost and geographical power and with explicit mechanisms to prevent the distribution of generation facilities. Congestion is exercise of market power. neither good nor bad but is a direct measure of the extent to which there are differences in the cost of PJM should continue to consider whether additional generation that cannot be equalized because of ancillary service markets need to be defined in order transmission constraints. A complete set of markets to ensure that the market is compensating suppliers would permit direct competition between for services when appropriate. investments in transmission and generation. The transmission system provides a physical hedge Overall, the MMU concludes that the Regulation against congestion. The transmission system is Markets results cannot be determined to have paid for by firm load and, as a result, firm load been competitive or to have been noncompetitive. receives the corollary financial hedge in the form of The MMU concludes that the Synchronized Reserve ARRs and/or FTRs. While the transmission system Markets results were competitive. and, therefore, ARRs/FTRs are not guaranteed to be a complete hedge against congestion, ARRs/

FTRs do provide a substantial offset to the cost of congestion to firm load.46 45 This is referred to as dispatching units out of economic merit order. Economic merit order is the order of all generator offers from lowest to highest cost.

Congestion occurs when loadings on transmission facilities mean that the next unit in merit order cannot be used and that a higher cost unit must be used in its place.

46 See the 2007 State of the Market Report, Volume II, Section 8, Financial Transmission and Auction Revenue Rights, at ARR and FTR Revenue and Congestion.

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I The MMU analyzed congestion and its influence on Congestion Component of LMP and PJM markets during 2007. In doing so, comparison Facility or Zonal Congestion to 2006 and certain other prior years was required.

Congestion Component of LMP. To provide Congestion Cost an indication of the geographic dispersion of congestion costs, the congestion component

Total Congestion. Total congestion costs of LMP (CLMP) was calculated for control increased by $241 million or 15 percent, from zones in PJM. Price separation between

$1.603 billion in calendar year 2006 to $1.845 eastern and western control zones in PJM was billion in calendar year 2007. Day-ahead primarily a result of congestion on the Bedington congestion costs increased by $368 million or Black Oak and 5004/5005 interfaces. These 22 percent, from $1.707 billion in calendar year constraints generally had the effect of increasing 2006 to $2.075 billion in calendar year 2007. prices in eastern control zones located on the Balancing congestion costs decreased by constrained side of the affected facilities while

$126 million or 122 percent, from -$104 million reducing prices in the unconstrained western in calendar year 2006 to -$230 million in control zones.

calendar year 2007. Total congestion costs have ranged from 6 percent to 9 percent of

Congested Facilities. As was the case in PJM annual total billings since 2003. Congestion 2006, congestion frequency was significantly costs were 6 percent of total PJM billings for higher in the Day-Ahead Market compared to 2007, compared to 8 percent in 2006. Total the Real-Time Market in 2007.47 Day-ahead PJM billings for 2007 were $30.556 billion, a congestion frequency increased in calendar 46 percent increase from the $20.945 billion year 2007 compared to 2006. In 2007, there billed in 2006. (See Table 16.) were 62,216 day-ahead, congestion-event hours compared to 56,299 congestion-event Table 16 Total annual PJM congestion (Dollars hours in 2006. Day-ahead, congestion-event (Millions)): Calendar years 2003 to 2007 hours increased on Midwest ISO flowgates, interfaces and lines while congestion frequency Congestion Percent Total Percent of Charges Change PJM Billing PJM Billing on transformers decreased in 2007 compared to 2006. Real-time congestion frequency 2003 $464 NA $6,900 7%

increased in calendar year 2007 compared to 2004 $750 62% $8,700 9%

2006. In 2007, there were 19,527 real-time, 2005 $2,092 179% $22,630 9%

congestion-event hours compared to 19,510 2006 $1,603 (23%) $20,945 8%

congestion-event hours in 2006. Real-time, 2007 $1,845 15% $30,556 6%

congestion-event hours increased on Midwest Total $6,754 $89,731 8% ISO flowgates, interfaces and transformers, while lines saw decreases. The Bedington Black Oak Interface was the largest contributor

Monthly Congestion. Fluctuations in monthly to congestion costs in both 2006 and 2007.

congestion costs continued to be substantial.

In 2007, these differences were driven by 47 Prior state of the market reports measured real-time congestion frequency varying load and energy import levels, different using the convention that a congestion-event hour exists if the particular facility is constrained for four or more of the 12 five-minute intervals comprising that patterns of generation, weather-induced hour. In the 2007 State of the Market Report, in order to have a consistent changes in demand and variations in congestion metric for real-time and day-ahead congestion frequency, real-time congestion frequency is measured using the convention that an hour is constrained if any frequency on constraints affecting large of its component five-minute intervals is constrained. Comparisons to previous periods use the new standard for both current and prior periods.

portions of PJM load.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report With $714 million in total congestion costs, it

Zonal Congestion. In calendar year 2007, the accounted for 39 percent of the total PJM AP Control Zone experienced the highest congestion costs in 2007. The top four congestion cost of any control zone in PJM.

constraints in terms of congestion costs The $448.6 million in congestion costs in the together contributed $1.159 billion, or 63 AP Control Zone represented a 32 percent percent, of the total PJM congestion costs in increase from the $340.1 million in congestion 2007. The top four constraints also included costs the zone had experienced in 2006. The the Cloverdale Lexington line and the Bedington Black Oak Interface and the 5004/5005 and AP South interfaces. Cloverdale Lexington line constraints Table 17 Congestion summary (By facility type): Calendar year 2007 Congestion Costs (Millions)

Day Ahead Balancing Event Hours Load Generation Load Generation Grand Day Real Type Payments Credits Explicit Total Payments Credits Explicit Total Total Ahead Time Flowgate ($10.4) ($14.9) $4.4 $9.0 ($19.6) ($19.0) ($14.4) ($15.0) ($6.0) 1,489 1,069 Interface $440.8 ($528.1) $58.8 $1,027.7 $466.7 $483.9 ($19.3) ($36.6) $991.1 9,798 2,856 Line ($295.8) ($901.3) $67.6 $673.1 $71.4 $121.5 ($101.4) ($151.5) $521.6 39,071 10,916 Transformer $128.0 ($192.3) $32.1 $352.4 ($34.5) ($31.9) ($24.3) ($27.0) $325.4 11,858 4,686 Unclassified $12.2 $1.1 $1.3 $12.4 $0.0 $0.0 $0.0 $0.0 $12.4 NA NA Total $274.9 ($1,635.5) $164.2 $2,074.6 $484.0 $554.6 ($159.5) ($230.1) $1,844.5 62,216 19,527 Table 18 Congestion summary (By facility type): Calendar year 2006 Congestion Costs (Millions)

Day Ahead Balancing Event Hours Load Generation Load Generation Grand Day Real Type Payments Credits Explicit Total Payments Credits Explicit Total Total Ahead Time Flowgate ($15.2) ($18.4) $2.0 $5.2 ($19.3) ($18.2) ($10.0) ($11.2) ($6.0) 1,350 859 Interface $1,459.1 $726.8 $20.1 $752.4 $1,302.3 $1,284.5 ($6.2) $11.6 $764.0 8,273 2,792 Line ($94.3) ($645.5) $34.3 $585.5 $235.5 $286.4 ($38.7) ($89.6) $495.8 34,558 11,447 Transformer $391.9 $59.1 $16.4 $349.2 $471.8 $468.7 ($17.6) ($14.6) $334.6 12,118 4,412 Unclassified $25.8 $13.8 $3.0 $14.9 $0.0 $0.0 $0.0 $0.0 $14.9 NA NA Total $1,767.2 $135.9 $75.8 $1,707.1 $1,990.3 $2,021.5 ($72.6) ($103.8) $1,603.4 56,299 19,510 38 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I together contributed $286.9 million, or 64 Economic Planning Process percent of the total AP Control Zone congestion cost. The Dominion Control Zone had the

Process Revision. PJM has made multiple second highest congestion cost in PJM in filings related to economic metrics for evaluating 2007. The $290.8 million in congestion costs transmission investments. The FERC has in the Dominion Control Zone represented a 29 required that PJM use an approach with percent increase from the $224.7 million in predefined formulas for determining whether a congestion costs the zone had experienced in defined transmission investment passes the 2006. The Bedington Black Oak Interface cost-benefit test including explicit accounting and Cloverdale Lexington line constraints for changes in production costs, the costs of together contributed $185.5 million, or 64 complying with environmental regulations, percent of the total Dominion Control Zone generation availability trends and demand-congestion cost. response trends. On October 9, 2007, PJM submitted its compliance filing to address these issues and to provide a formulaic approach for including transmission projects Table 19 Congestion cost summary (By control zone): Calendar year 2007 Congestion Costs (Millions)

Day Ahead Balancing Control Load Generation Load Generation Grand Zone Payments Credits Explicit Total Payments Credits Explicit Total Total AECO $81.2 $35.6 $0.3 $45.8 $92.3 $90.5 ($0.4) $1.3 $47.1 AEP ($1,369.5) ($1,659.2) $12.8 $302.6 ($1,340.9) ($1,225.8) ($2.0) ($117.1) $185.5 AP $72.4 ($388.5) $43.1 $503.9 $14.1 $54.4 ($15.0) ($55.3) $448.6 BGE $407.4 $358.6 $8.9 $57.7 $498.6 $460.4 ($12.5) $25.8 $83.4 ComEd ($1,569.5) ($1,673.2) ($1.1) $102.6 ($941.7) ($1,019.7) $0.3 $78.3 $180.9 DAY ($181.0) ($198.8) ($0.1) $17.8 ($185.2) ($178.7) ($0.0) ($6.6) $11.2 DLCO ($321.6) ($406.9) ($0.0) $85.2 ($200.6) ($158.4) $0.0 ($42.2) $43.0 Dominion $920.8 $644.9 $30.8 $306.7 $1,117.0 $1,111.3 ($21.6) ($15.9) $290.8 DPL $126.4 $61.1 $1.3 $66.6 $134.3 $129.2 ($2.2) $2.9 $69.5 External ($76.3) ($24.3) $11.0 ($40.9) ($11.7) ($31.8) ($74.9) ($54.8) ($95.7)

JCPL $233.0 $79.0 $4.0 $158.0 $206.9 $198.0 ($4.0) $4.9 $162.9 Met-Ed $123.5 $92.7 $5.1 $35.9 ($0.7) $10.3 $17.3 $6.3 $42.2 PECO $451.2 $479.0 $0.7 ($27.2) $15.5 $41.7 ($0.9) ($27.0) ($54.2)

PENELEC ($177.6) ($342.7) $4.5 $169.5 ($7.5) $11.8 ($1.3) ($20.6) $148.9 Pepco $773.2 $634.7 $13.5 $152.0 $678.8 $622.5 ($18.6) $37.7 $189.6 PPL $400.1 $410.6 $7.9 ($2.6) $27.6 $32.0 $1.8 ($2.6) ($5.3)

PSEG $371.0 $261.2 $21.1 $130.9 $376.4 $396.3 ($24.9) ($44.9) $86.0 RECO $10.3 $0.5 $0.5 $10.3 $10.8 $10.5 ($0.6) ($0.3) $9.9 Total $274.9 ($1,635.5) $164.2 $2,074.6 $484.0 $554.6 ($159.5) ($230.1) $1,844.5

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report in the Regional Transmission Expansion Plan underlying inability of the transmission system to (RTEP). Under PJMs proposed approach, transfer the lowest-cost energy on the system to all PJM would perform market simulations with parts of the system for all hours. The details are and without the proposed transmission revealed in the analysis of temporal patterns of investments, including reliability-based congestion and of congested facilities and zonal investments and economic investments. The congestion. That information, made explicit over result would be used to determine the economic the broad PJM footprint, is an essential input to a benefits of the investments and whether to rational market and planning process.

include such investment in the RTEP. An economic investment would be included in the ARRs and FTRs served as an effective hedge RTEP if the relative benefits and costs of the against congestion. In total, ARR and FTR revenues investment meet a benefit/cost ratio threshold hedged 98.4 percent of congestion costs in the of at least 1.25:1. Day-Ahead Energy Market and in the balancing energy market within PJM for the 2006 to 2007 Conclusion planning period and 92.3 percent of the congestion costs in PJM in the first seven months of the 2007 Congestion reflects the underlying characteristics to 2008 planning period.48 FTRs were paid at 100 of the power system, including the nature and percent of their target allocation for the planning capability of transmission facilities and the cost and year ended May 31, 2007, and at 100 percent of geographical distribution of generation facilities. their target allocation for the first seven months of Total congestion costs increased by $241 million or the current planning year.

15 percent, from $1.603 billion in calendar year 2006 to $1.845 billion in calendar year 2007. Day- One constraint accounted for over a third of total ahead congestion costs increased by $368 million congestion costs in 2007 and the top four or 22 percent, from $1,707 billion in calendar year constraints accounted for nearly two-thirds of total 2006 to $2.075 billion in calendar year 2007. congestion costs. The largest constraint has been Balancing congestion costs decreased by $126 a persistent source of large congestion costs for million or 122 percent, from -$104 million in calendar several years. This suggests that these constraints year 2006 to -$230 million in calendar year 2007. should receive special attention in the economic Congestion costs were significantly higher in the planning process. The Bedington Black Oak Day-Ahead Market than in the balancing market. Interface was the largest contributor to congestion Congestion frequency was also significantly higher costs in both 2007 and 2006 and, with $714 million in the Day-Ahead Market than in the Real-Time in total congestion costs, accounted for 39 percent Market. In the Day-Ahead Market in 2007, there of the total PJM congestion costs in 2007. The top were 62,216 congestion-event hours compared to four constraints in terms of congestion costs 56,299 congestion-event hours in 2006. In the together accounted for 63 percent of the total PJM Real-Time Energy Market in 2007, there were congestion costs in 2007.

19,527 congestion-event hours compared to 19,510 congestion-event hours in 2006.

As a result of the geographic growth of PJM, efficient redispatch displaced the less efficient management of borders via transmission loading relief (TLR) procedures and ramp limits. Redispatch 48 See the 2007 State of the Market Report, Volume II, Section 8, Financial is more efficient and, at the same time, revealed the Transmission and Auction Revenue Rights, at Table 8-22, ARR and FTR congestion hedging: Planning periods 2006 to 2007 and 2007 to 2008.

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I Financial Transmission and delivery. Firm transmission service customers Auction Revenue Rights receive requested ARRs/FTRs to the extent that they are consistent both with the physical capability FTRs and ARRs give transmission service customers of the transmission system and with ARR/FTR and PJM members an offset against congestion requests of other eligible customers.

costs in the Day-Ahead Energy Market. An FTR provides the holder with revenues, or charges, The 2007 State of the Market Report focuses on equal to the difference in congestion prices in the two FTR/ARR planning periods: the 2006 to 2007 Day-Ahead Energy Market across the specific FTR planning period which covers June 1, 2006, through transmission path. An ARR is a related product that May 31, 2007, and the 2007 to 2008 planning provides the holder with revenues, or charges, period which covers June 1, 2007, through May based on the price differences across the specific 31, 2008.

ARR transmission path that result from the Annual FTR Auction. FTRs and ARRs provide a hedge FTRs against congestion costs, but neither FTRs nor ARRs provide a guarantee that transmission service Market Structure customers will not pay congestion charges. ARR and FTR holders do not need to physically deliver

Supply. PJM operates an Annual FTR Auction energy to receive ARR or FTR credits and neither for all control zones in the PJM footprint. PJM instrument represents a right to the physical delivery conducts Monthly Balance of Planning Period of energy. FTR Auctions for the remaining months of the planning period, to allow participants to buy In PJM, FTRs have been available to network and sell any residual transmission capability.

service and long-term, firm, point-to-point PJM also administers a secondary bilateral transmission service customers as a hedge against market to allow participants to buy and sell congestion costs since the inception of LMP on existing FTRs. FTR products include FTR April 1, 1998. Effective June 1, 2003, PJM replaced obligations and FTR options. Each of these is the allocation of FTRs with an allocation of ARRs available for 24-hour, on-peak and off-peak and an associated Annual FTR Auction.49 Since the periods. FTRs have terms varying from one introduction of this auction, FTRs have been month to one year. FTR supply is limited by the available to all transmission service customers and capability of the transmission system to PJM members. Network service and firm point-to- accommodate simultaneously the set of point transmission service customers can take requested FTRs and the numerous allocated ARRs or the underlying FTRs through a combinations of FTRs. The principal binding self-scheduling process. On June 1, 2007, PJM constraints limiting the supply of FTRs in the implemented marginal losses in the calculation of Annual FTR Auction for the 2007 to 2008 LMP. Since then, FTRs have been valued based on planning period include the Bedington Black the difference in congestion prices rather than the Oak Interface and the Meadowbrook difference in LMPs. transformer.50 Market participants can also sell Firm transmission service customers have access 50 During calendar years 2004 and 2005, PJM conducted the phased integration to ARRs/FTRs because they pay the costs of the of five control zones. Four of these, American Electric Power (AEP), The Dayton Power & Light Company (DAY), Duquesne Light Company (DLCO) and Dominion, transmission system that enables firm energy were eligible for direct allocation FTRs during the 2006 to 2007 planning period, but not the 2007 to 2008 planning period. For additional information on the integrations, their timing and their impact on the footprint of the PJM service territory, see the 2007 State of the Market Report, Volume II, Appendix 49 87 FERC ¶ 61,054 (1999). A, PJM Geography.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report FTRs. For the 2007 to 2008 planning period, in part, in a PJM filing.53 These are being total FTR sell offers were 117,199 MW, up from investigated.

76,669 MW during the 2006 to 2007 planning period. In the Monthly Balance of Planning

Patterns of Ownership. Ownership of FTR Period FTR Auctions for the first seven months products is moderately concentrated and (June through December 2007) of the 2007 to maximum market shares exceed 20 percent in 2008 planning period, there were 1,912,181 some cases based on the results of the Annual MW of FTR sell offers. FTR Auction. The FTR options market is more concentrated than the market for FTR

Demand. There is no limit on FTR demand in obligations. The level of concentration is only any FTR auction. In the Annual FTR Auction for descriptive and is not a measure of the the 2007 to 2008 planning period, total FTR competitiveness of FTR market structure as buy bids were 2,223,687 MW, up from the ownership positions resulted from a 1,570,121 MW during the 2006 to 2007 competitive auction. In order to evaluate the planning period. Total FTR self-scheduled bids ownership of prevailing flow and counterflow were 71,360 MW for the 2007 to 2008 planning FTRs, the MMU categorized all participants period, an increase from 38,301 MW for the owning FTRs in PJM as either physical or 2006 to 2007 planning period. In the Monthly financial. Physical entities include utilities and Balance of Planning Period FTR Auctions for customers which primarily take physical the first seven months (June through December positions in PJM markets. Financial entities 2007) of the 2007 to 2008 planning period, include banks and hedge funds which primarily total FTR buy bids were 8,427,824 MW. take financial positions in PJM markets.

Physical entities own slightly more than half of

FTR Credit Issues. Two participants defaulted prevailing flow FTRs while financial entities own on their FTR-related payment obligations in about three quarters of counterflow FTRs.

2007 as the result of inadequate collateral held Overall, the ownership of all FTRs is about by PJM to cover the participants losses evenly split between physical and financial resulting from counterflow FTR positions. The entities.

defaults made it clear that PJM credit polices related to FTRs and particularly to counterflow Market Performance FTRs were inadequate. On December 21, 2007, PJM submitted to the FERC revisions to

Volume. For the 2007 to 2008 planning period, its Open Access Transmission Tariff (OATT) to the Annual FTR Auction cleared 208,637 MW improve the credit requirements for FTR market (9.4 percent) of FTR buy bids, up from 129,866 participants.51 PJM submitted an additional MW (8.3 percent of demand) for the 2006 to filing on January 31, 2008, to the FERC to 2007 planning period. The Annual FTR Auction increase the credit requirement for market also cleared 6,495 MW (5.5 percent) of FTR participants with net counterflow FTR sell offers for the 2007 to 2008 planning period, positions.52 The defaults also raised potential down from 10,056 MW (13.1 percent) for the market gaming issues, which were addressed, 2006 to 2007 planning period. For the first seven months of the 2007 to 2008 planning 51 PJM Interconnection, L.L.C., PJM Interconnection, L.L.C. submits revisions to the PJM Credit Policy Attachment Q, Docket No. ER08-376-000 (December 26, 2007).

52 PJM Interconnection, L.L.C., PJM Interconnection, L.L.C. submits revisions 53 PJM Interconnection, L.L.C. made a filing under section 205 of the Federal to the Credit Policy Attachment Q of their Open-Access Transmission Tariff, Power Act to amend section 15.2 of the PJM Operating Agreement concerning FERC Electric Tariff, Sixth Revised Volume 1, to become effective April 1, 2008, defaults on short FTR portfolios in Docket No. ER08-455-000, (January 18, Docket No. ER08-520-000 (January 31, 2008). 2008).

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I period, the Monthly Balance of Planning Period million in net revenue for all FTRs during the FTR Auctions cleared 610,829 MW (7.2 first seven months of the 2007 to 2008 planning percent) of FTR buy bids and 155,606 MW (8.1 period.

percent) of FTR sell offers. There were no direct allocation FTRs for the 2007 to 2008 planning

Revenue Adequacy. FTRs were 100 percent period. revenue adequate for the 2006 to 2007 planning period. FTRs were paid at 100 percent

Price. For the 2007 to 2008 planning period, of the target allocation level for the first seven 85 percent of the annual FTRs were purchased months of the 2007 to 2008 planning period.

for less than $1 per MWh and 90.9 percent for Congestion revenues are allocated to FTR less than $2 per MWh. For the 2007 to 2008 holders based on FTR target allocations. PJM planning period, the weighted-average prices collected $1,532.7 million of FTR revenues paid for annual buy-bid FTR obligations were during the first seven months of the 2007 to

$0.35 per MWh for 24-hour FTRs, $0.57 per 2008 planning period and $1,906.1 million MWh for on-peak FTRs and $0.47 per MWh during the 2006 to 2007 planning period. For for off-peak FTRs. Comparable, weighted- the first seven months of the 2007 to 2008 average prices for the 2006 to 2007 planning planning period, the top sink and top source period were $1.95 per MWh for 24-hour and with the highest positive FTR target allocations

$0.78 per MWh for both on-peak and off-peak were the AP Control Zone and the Western FTRs. The weighted-average prices paid for Hub, respectively. Similarly, the top sink and 2007 to 2008 planning period annual buy-bid top source with the largest negative FTR target FTR obligations and options were $0.47 per allocations were the Western Hub and Atlantic, MWh and $0.37 per MWh, respectively, respectively.

compared to $1.12 per MWh and $0.29 per MWh, respectively, in the 2006 to 2007 ARRs planning period.54 The weighted-average price paid in the Monthly Balance of Planning Period Market Structure FTR Auctions for the first seven months of the 2007 to 2008 planning period was $0.18 per

Supply. ARR supply is limited by the capability MWh, compared with $0.22 per MWh in the of the transmission system to simultaneously Monthly Balance of Planning Period FTR accommodate the set of requested ARRs and Auctions for the full 12-month 2006 to 2007 the numerous combinations of feasible ARRs.

planning period. The principal binding constraints that limited supply in the annual ARR allocation for the

Revenue. The Annual FTR Auction generated 2007 to 2008 planning period were the

$1,698.03 million of net revenue for all FTRs Bedington Black Oak and AP South during the 2007 to 2008 planning period, up interfaces. A new ARR product was added for from $1,417.5 million for the 2006 to 2007 the 2007 to 2008 planning period. Long-term planning period. The Monthly Balance of ARRs are in effect for 10 consecutive planning Planning Period FTR Auctions generated $28.2 periods and are available in Stage 1A of the annual ARR allocation. Residual ARRs were 54 Weighted-average prices for FTRs in the Annual FTR Auction and Monthly also introduced and are available to holders Balance of Planning Period FTR Auctions are the average prices weighted by the MW and hours in a time period (planning period or month) for each FTR with prorated Stage 1A or 1B ARRs if additional class type: 24-hour, on peak and off peak. For example, FTRs in the Annual FTR Auction would be weighted by their MW and the hours in that time period transmission capability is added during the for each FTR class type: 24-hour (8,760 hours0.0088 days 0.211 hours 0.00126 weeks 2.8918e-4 months ), on peak (4,080 hours9.259259e-4 days 0.0222 hours 1.322751e-4 weeks 3.044e-5 months ) and off peak (4,680 hours0.00787 days 0.189 hours 0.00112 weeks 2.5874e-4 months ).

planning period.

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report

Demand. Total demand in the annual ARR Eligible market participants self-scheduled allocation was 150,822 MW for the 2007 to 38,301 MW (56.7 percent) of these allocated 2008 planning period with 62,220 MW bid in ARRs as annual FTRs.

Stage 1A, 31,063 MW bid in Stage 1B and 57,539 MW bid in Stage 2. This is up from

Revenue. As ARRs are allocated to qualifying 99,412 MW for the 2006 to 2007 planning customers rather than sold, there is no ARR period with 56,705 MW bid in Stage 1 and revenue comparable to the revenue that results 42,707 MW bid in Stage 2. ARR demand is from the FTR auctions.

limited by the total amount of network service and firm point-to-point transmission service.

Revenue Adequacy. During the 2007 to 2008 planning period, ARR holders will receive

ARR Reassignment for Retail Load Switching. $1,640 million in ARR credits, with an average When retail load switches among LSEs, a hourly ARR credit of $1.73 per MWh. During proportional share of the ARRs and their the 2007 to 2008 planning period, the ARR associated revenue are reassigned from the target allocations were $1,640 million while LSE losing load to the LSE gaining load. ARR PJM collected $1,726 million from the reassignment occurs only if the LSE losing load combined Annual and Monthly Balance of has ARRs with a net positive economic value. Planning Period FTR Auctions through An LSE gaining load in the same control zone December 31, 2007, making ARRs revenue is allocated a proportional share of positively adequate. During the 2006 to 2007 planning valued ARRs within the control zone based on period, ARR holders received $1,405 million in the shifted load. There were 10,054 MW of ARR credits, with an average hourly ARR credit ARRs associated with $326,800 per MW-day of $2.37 per MWh. For the 2006 to 2007 of revenue that were reassigned in the first planning period, the ARR target allocations seven months of the 2007 to 2008 planning were $1,405 million while PJM collected period. $1,435 million from the combined Annual and Monthly Balance of Planning Period FTR Market Performance Auctions, making ARRs revenue adequate.

Volume. Of 150,822 MW in ARR requests for

ARR Proration. When ARRs were allocated for the 2007 to 2008 planning period, 107,992 the 2007 to 2008 planning period, some of the MW (71.6 percent) were allocated. There were requested ARRs were prorated as a result of 62,211 MW allocated in Stage 1A, 29,444 MW binding transmission constraints. For the 2007 allocated in Stage 1B and 16,337 MW allocated to 2008 planning period, no ARRs were in Stage 2. Eligible market participants self- prorated in Stage 1A of the annual ARR scheduled 71,360 MW (66.1 percent) of these allocation. In Stage 1B, the only constraint allocated ARRs as annual FTRs. Demand for affecting the ARR allocation was the Cedar ARRs increased because of load growth and Grove Clifton line. There were 1,159.3 MW the requirement that the AEP, DAY, DLCO and of Stage 1B ARRs denied to participants Dominion control zones take ARR allocations, whose requested ARRs affected that binding instead of direct allocation FTRs. Of 99,412 transmission constraint.

MW in ARR requests for the 2006 to 2007 planning period, 67,568 MW (68 percent) were

ARR and FTR Revenue and Congestion. The allocated. There were 54,430 MW allocated in effectiveness of ARRs and FTRs as a hedge Stage 1 and 13,138 MW allocated in Stage 2. against actual congestion can be measured 44 © PJM Interconnection 2008 l www.pjm.com

VOL UM E 2007 State of the Market Report I n t r o d u c ti o n I several ways. The first is to compare the Conclusion revenue received by ARR holders against the congestion costs experienced by these ARR The annual ARR allocation and the Annual FTR holders. The second is to compare the revenue Auction together provide long-term, firm received by FTR holders against the total transmission service customers with a mechanism congestion costs within PJM. The final and to hedge congestion and provide all market comprehensive method is to compare the participants increased access to long-term FTRs.

revenue received by all ARR and FTR holders The Annual FTR Auction and the Monthly Balance to total actual congestion costs in the Day- of Planning Period FTR Auctions provide a market Ahead Energy Market and the balancing energy valuation of FTRs. The FTR auction results for the market within PJM. During the 2006 to 2007 2007 to 2008 planning period were competitive planning period, total ARR and FTR revenues and succeeded in providing all qualified market hedged 98.4 percent of the congestion costs participants with equal access to FTRs. The rules within PJM. For the first seven months of the for ARR reassignment when load shifts should 2007 to 2008 planning period, all ARRs and address the fact that in the case of ARRs self-FTRs hedged 92.3 percent of the congestion scheduled as FTRs, the underlying FTRs do not costs within PJM. follow the load while the ARRs do.

Table 110 ARR and FTR congestion hedging by control zone: Planning period 2006 to 2007 Total Hedge -

Control FTR Auction Total ARR and Congestion Percent Zone ARR Credits FTR Credits Revenue FTR Hedge Congestion Difference Hedged AECO $41,133,569 $42,768,075 $60,230,082 $23,671,562 $67,085,194 ($43,413,632) 35.3%

AEP $11,313,430 $164,687,852 ($35,943,010) $211,944,292 $166,314,810 $45,629,482 127.4%

AP $651,180,242 $569,068,207 $572,185,631 $648,062,818 $420,202,812 $227,860,006 154.2%

BGE $65,120,212 $44,177,535 $44,624,675 $64,673,072 $105,375,274 ($40,702,202) 61.4%

ComEd $8,862,245 $18,451,540 ($9,118,361) $36,432,146 $135,684,232 ($99,252,086) 26.9%

DAY $2,148,066 $2,073,735 ($6,460,296) $10,682,097 $11,743,208 ($1,061,111) 91.0%

DLCO $2,304,673 ($6,381,093) ($21,902,476) $17,826,056 $49,965,737 ($32,139,681) 35.7%

Dominion $60,102,387 $243,308,757 $44,156,816 $259,254,328 $280,205,524 ($20,951,196) 92.5%

DPL $24,817,167 $40,790,763 $44,464,780 $21,143,150 $99,543,825 ($78,400,675) 21.2%

JCPL $52,986,630 $41,450,855 $68,688,063 $25,749,422 $113,257,858 ($87,508,436) 22.7%

Met-Ed $50,448,008 $58,987,745 $50,447,353 $58,988,400 $18,714,551 $40,273,849 315.2%

PECO $114,251,938 $90,294,949 $128,528,732 $76,018,155 ($55,606,384) $131,624,539 >100 %

PENELEC $53,844,756 $69,419,846 $79,169,254 $44,095,348 $120,583,245 ($76,487,897) 36.6%

Pepco $44,747,368 $141,801,096 $132,288,429 $54,260,035 $201,191,153 ($146,931,118) 27.0%

PJM $12,103,102 $18,234,521 $10,571,744 $19,765,879 ($76,889,434) $96,655,313 >100 %

PPL $72,426,920 $51,180,375 $71,887,428 $51,719,867 ($32,339,599) $84,059,466 >100 %

PSEG $135,412,323 $131,199,665 $198,188,719 $68,423,269 $85,602,232 ($17,178,963) 79.9%

RECO $1,443,947 $3,309,712 $2,744,571 $2,009,088 $12,121,505 ($10,112,417) 16.6%

Total $1,404,646,983 $1,724,824,135 $1,434,752,134 $1,694,718,984 $1,722,755,743 ($28,036,759) 98.4%

VOL UM E I I Nt r o d u c ti o n 2007 State of the Market Report ARRs were 100 percent revenue adequate for both Revenue adequacy must be distinguished from the the 2007 to 2008 and the 2006 to 2007 planning adequacy of FTRs as a hedge against congestion.

periods. FTRs were paid at 100 percent of the Revenue adequacy is a narrower concept that target allocation level for the 12-month period of compares the revenues available to cover the 2006 to 2007 planning period, and at 100 congestion across specific paths for which FTRs percent of the target allocation level for the first were available and purchased. The adequacy of seven months of the 2007 to 2008 planning period. FTRs as a hedge against congestion compares The total of ARR and FTR revenues hedged 98.4 FTR revenues to total congestion on the system as percent of the congestion costs in the Day-Ahead a measure of the extent to which FTRs hedged Energy Market and the balancing energy market market participants against actual, total congestion within PJM for the 2006 to 2007 planning period across all paths, regardless of the availability or and 92.3 percent of the congestion costs in PJM in purchase of FTRs.

the first seven months of the 2007 to 2008 planning period. PJM faced substantial participant defaults in 2007 as a result of participant counterflow positions in The ARR and FTR revenue adequacy results are the FTR markets in combination with inadequate aggregate results and all those paying congestion PJM credit requirements and inadequate participant charges were not necessarily hedged at that level. financial resources. PJM has taken steps to address Aggregate numbers do not reveal the underlying the credit issue. The defaults also raised potential distribution of FTR holders, their revenues or those market gaming issues, which were addressed, in paying congestion. part, in a PJM filing. These are being investigated.

ML083050232

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