WASHINGTON October 1, 2010

Transcription

1 CAMBRIDGE SAN FRANCISCO WASHINGTON October 1, 2010 BRUSSELS Terry J. Romine, Executive Secretary Maryland Public Service Commission William Donald Schaefer Tower 6 Saint Paul Street, 16 th Floor Baltimore, Maryland LONDON MADRID Re: Administrative Docket PC22 Dear Executive Secretary Romine: Enclosed are our comments in response to the August 16, 2010 Notice of Public Conference regarding the PJM Interconnection, LLC s Reliability Pricing Model and the 2013/14 Delivery Year Base Residual Auction Results (Administrative Docket PC22). If you have any questions, please feel free to contact us. Respectfully Submitted, Johannes Pfeifenberger Principal Kathleen Spees Associate Attachment A Attachment B Attachment C Attachment D Qualifications of Johannes P. Pfeifenberger Qualifications of Kathleen Spees Pfeifenberger, J., S. Newell, R. Earle, A. Hajos, and M. Geronimo. Review of PJM s Reliability Pricing Model (RPM). June 30, Pfeifenberger, J., K. Spees, and A. Schumacher. A Comparison of PJM s RPM with Alternative Energy and Capacity Market Designs. September Brattle Street Cambridge, MA Voice Facsimile office@brattle.com

2 STATE OF MARYLAND BEFORE THE PUBLIC SERVICE COMMISSION In the Matter of the Reliability Pricing ) Model and the 2013/2014 Delivery Year ) Administrative Docket PC22 Year Base Residual Auction Results ) COMMENTS OF JOHANNES P. PFEIFENBERGER AND KATHLEEN SPEES 1 We are pleased to submit comments in response to the State of Maryland Public Service Commission August 16, 2010 Notice of Public Conference regarding the PJM Interconnection, LLC s Reliability Pricing Model and the 2013/14 Delivery Year Base Residual Auction Results. These comments represent only our own views and are not the views of The Brattle Group, its clients, or any other organizations with whom it is associated. I. INTRODUCTION AND SUMMARY Johannes Pfeifenberger is a Principal and Kathleen Spees is an Associate of The Brattle Group. Mr. Pfeifenberger leads the firm s utility practice area. He has previously been engaged with several of our colleagues by PJM Interconnection, LLC to undertake an independent evaluation of its forward capacity market, the Reliability Pricing Model ( RPM ), as mandated by the Federal Energy Regulatory Commission ( FERC ). The results of our RPM review were published in the report Review of PJM's Reliability Pricing Model, which was filed with FERC on June 30, In this report we analyzed whether RPM was succeeding in addressing the capacity resource needs that it was intended to address. We also made a number of recommendations to refine the design of RPM, many of which PJM has since implemented. Mr. Pfeifenberger and Dr. Spees are also authors of a September 2009 report, A Comparison of PJM's RPM with Alternative Energy and Capacity Market Designs, which was prepared for PJM in response to a request by state commissions for an independent analysis that would compare and contrast RPM with alternative power market designs, evaluate each design s ability to maintain resource adequacy, and summarize the experience from other U.S. and international power markets. 3 This report analyzed the advantages and disadvantages of the different market design options partly as a function of a region s wholesale and retail market structure. Mr. Pfeifenberger presented conclusions from this analysis of alternative market designs in his Mr. Pfeifenberger is a Principal and Dr. Kathleen Spees is an Associate of The Brattle Group ( PJM is sponsoring the submission of these comments. However, the views expressed herein are the authors own. See Attachment C, posted at: See Attachment D, posted at: 2

3 keynote speaker presentation at PJM s Long Term Capacity Issues Symposium on January 27, The findings and conclusions from these reports and from additional analysis of RPM auction results that we have undertaken in preparing these comments directly address some of the questions set out in the Commission s August 16, 2010 Notice of Public Conference. As we explain in more detail in the remainder of these comments, we find that: Capacity market prices under RPM have been consistent with the level of resources committed in the market relative to reliability requirements; this is the case both on an RTO-wide basis as well as within individual Locational Deliverability Areas ( LDAs ). The differing price levels among LDAs are consistent with regional differences in available capacity resources and regional transmission constraints. Levelization of capacity prices across the RTO would ignore locational differences in market fundamentals and thus would not be desirable. RPM has been successful in retaining a substantial quantity of generating capacity, at the RTO-wide level and particularly within LDAs; without the revenues provided by RPM, several thousand MW of capacity would be at risk for retirement within major LDAs, such as the Mid-Atlantic Area Council ( MAAC ), Southwestern MAAC ( SWMAAC ) and Eastern MAAC ( EMAAC ). RPM has attracted the addition of substantial new capacity resources, including both physical generating capacity and demand-response resources. Incremental commitment by demand-response resources have been particularly pronounced within LDAs such as SWMAAC and EMAAC. In electricity markets with retail access like eastern PJM, a forward capacity market design such as RPM offers significant advantages over alternative wholesale electricity market designs; RPM should consequently be retained. Stability in the market design is an important consideration for investors willing to fund new resources; the adverse impact of regulatory risk therefore needs to be considered in refining the market design over time. II. PURPOSE AND BENEFITS OF THE RELIABILITY PRICING MODEL The purpose of RPM is to use market-based price signals to attract and retain the lowest-cost sources of capacity on a forward basis when and where needed to maintain adequate reliability. A market-based approach to maintaining resource adequacy requires that total returns to suppliers obtained from the capacity, energy, and ancillary services markets must be consistent with market conditions. This means that prices will need to be high enough to attract new entry and retain existing resources when and where the resources are needed. Prices will be below the net cost of new entry (discouraging additional investments) in locations with capacity surplus. This also means that locational transmission constraints must be observed when determining the relative capacity surplus or scarcity in regions such as the MAAC, SWMAAC, or Potomac Electric Power Company ( PEPCO ) LDAs. It is important to recognize that the locationspecific nature of resource adequacy is not defined by state boundaries but rather by the physical limits of the regional transmission system. 4 Best Practices in Resource Adequacy, posted at: 3

4 The purpose of RPM is not to achieve any particular capacity price outcome, nor is it to achieve low prices, nor to guarantee sufficient returns to investors, nor to achieve equal prices in all locations. In fact, forcing such outcomes through means other than market-based responses could be quite detrimental to locational reliability because the location-specific price signals would be inconsistent with the underlying supply-demand fundamentals, including locational scarcity. In addition, the capacity price outcomes from any one auction individually are not an appropriate basis upon which to judge the efficiency and effectiveness of the market design. Instead, market effectiveness should be judged cumulatively over several years or an even longer period of time. Such an assessment should examine whether the design is meeting locational reliability objectives and whether resulting market prices are consistent with the underlying market fundamentals. Our comparison of PJM with alternative energy and capacity market designs internationally has confirmed that the forward capacity market design offers substantial advantages in restructured power markets with retail access such as Maryland and other states in eastern PJM. The alternative market designs we evaluated included: (1) energy-only markets like ERCOT and several international markets, (2) energy markets with administratively-determined capacity payments like Spain, (3) energy markets with reserve requirements but without centralized capacity markets like SPP, (4) energy markets with centralized capacity markets like NYISO and Midwest ISO, (5) energy markets with forward reserve requirements but without centralized capacity markets like California ISO, and (6) energy markets with forward centralized capacity markets like PJM and ISO-NE. 5 In this review of alternative market designs, we found that resource adequacy standards imposed on load-serving entities ( LSEs ) are an effective market-based mechanism for maintaining predefined reliability targets and avoiding the frequent severe price spikes that are required to maintain resource adequacy in energy-only markets. The existence of a resource adequacy standard creates a bilateral market for capacity as LSEs must either self-supply or bilaterally procure sufficient capacity to supply their own customers. Several of the U.S. markets with resource adequacy requirements are purely bilateral, including those in California, SPP, and regions without Regional Transmission Organizations ( RTOs ). Fully bilateral capacity have some advantages over centralized capacity markets, chiefly that they are less complex and less influenced by administrative parameters. On the down side, solely bilateral capacity markets lack transparency and liquidity, impose higher transaction costs in a retail access environment, and make it difficult to monitor or mitigate potential exercise of market power. The 3-year forward procurement of capacity under RPM offers a number of additional advantages. By requiring resource commitments sufficiently prior to delivery, enough time is left for either market participants or the system operator to procure additional resources once deficiencies become apparent. The lead time gives suppliers enough time to modify their resource development plans, for example, by bringing back online mothballed plants, by making 5 The full names of these markets are the Electric Reliability Council of Texas ( ERCOT ), Southwest Power Pool ( SPP ), the New York Independent System Operator ( NYISO ), Midwest Independent Transmission System Operator ( Midwest ISO ), California Independent System Operator ( California ISO ), and the Independent System Operator for New England ( ISO-NE ). 4

5 the capital investment necessary to defer retirements, by speeding up the development of a new power plant, or by developing additional demand response ( DR ) resources. This increased ability to respond allows new resources to compete with existing resources, reduces the risk of market power abuses, and reduces price volatility. The advantages of combining the forward resource adequacy requirement with a mandatory RTO-administered market for residual capacity include: increased price transparency, lower transactions costs (particularly in markets with many small suppliers), facilitation of retail competition by lowering risks and transactions costs associated with load migration, improved integration of DR resources, and facilitation of monitoring and mitigation of market power. One important feature of effective resource adequacy requirements (with or without centralized capacity markets) is that they must be able to ensure local reliability needs by taking into account transmission constraints. Resource adequacy is both a region-wide and local problem, in that sufficient installed capacity must be available not only to the RTO as a whole, but also to smaller import-constrained subregions like in eastern PJM. These constrained subregions do not generally follow traditional state or even utility service area boundaries but instead are defined by limitations in the transmission system preventing power transfers during times of scarcity. Locational capacity markets such as RPM facilitate the cost-effective procurement of adequate resources for constrained subregions by observing these transmission constraints in capacity auctions. This results in the effective use of transmission capability by procuring lower-cost resources from outside the region to the extent possible, while still procuring sufficient resources from within the constrained zone to meet reliability requirements. III. RPM HAS PROCURED ADEQUATE CAPACITY RESOURCES AT PRICES CONSISTENT WITH LOCATIONAL MARKET FUNDAMENTALS Over the first seven delivery year auctions, the RPM market design has demonstrated its ability to procure adequate resources to meet reliability requirements on an RTO-wide basis, as well as ensuring that sufficient resources are deliverable to transmission-constrained LDAs. Figure 1 maps the constrained LDAs currently observed under RPM and Figure 2 contains a schematic of the nested hierarchy showing which utility service areas lower-level LDAs are contained within each higher-level LDA. As shown, Maryland covers all or portions of five different modeled LDAs, some of which are smaller LDAs nested inside larger LDAs. They include PEPCO, SWMAAC (which also includes all of PEPCO), DPL South, EMAAC (which also includes all of DPL South), and MAAC (which also includes all of SWMAAC and EMAAC). These LDAs reflect the transmission constraints into the heavily populated areas of eastern PJM within which it is difficult and expensive to add and retain generating resources. Figure 1 also shows that the western portion of Maryland is outside these LDAs in the unconstrained portion of the RTO. 5

6 Figure 1 Constrained Locational Deliverability Areas in RPM 6 MAAC Contains Subzones SWMAAC and EMAAC PSEG North EMAAC Contains PSEG and DPL South SWMAAC Contains Pepco PSEG Contains PSEG North Unconstrained RTO PEPCO DPL South Figure 2 Schematic of Nested Locational Deliverability Areas and Utility Service Areas Unconstrained RTO ComEd AEP Dayton Duquesne Allegheny Power Dominion MAAC MetEd PPL Penelec EMAAC RECO AECO PECO JCPL Northern DPL PSEG PSEG North DPL South SWMAAC BGE PEPCO Sources and Notes: See p. 11, PJM Capacity Market Manual 18. Modeled LDAs are shown as squares with name in bold. Other listed utility service areas (not in bold) are not their own LDAs. 6 The LDAs currently modeled in PJM are: the unconstrained RTO; the Mid-Atlantic Area Council ( MAAC ) which contains subzones Eastern MAAC ( EMAAC ) and Southwestern MAAC ( SWMAAC ); SWMAAC contains the Potomac Electric Power Company ( PEPCO ) subzone, SWMAAC also contains the Baltimore Gas and Electric ( BGE ) utility area, which is not a constrained LDA by itself; EMAAC contains the Delmarva Power and Light Company ( DPL ) South ( DPL South ) and Public Service Electric and Gas Company ( PSEG ) LDAs; PSEG contains PSEG North. 6

7 Figures 3 and 4 summarize resource adequacy and market clearing prices from the seven Base Residual Auctions ( BRAs ) conducted to date. Figure 3 shows that the quantity of capacity procured has ranged from 101.2%-104.7% of the reliability target for the RTO as a whole and, for example, from 97.4%-102.4% of the target in SWMAAC. The quantity procured does not exactly equal the reliability target because the Variable Resource Requirement ( VRR ) allows for less procurement when capacity is expensive and additional procurement when capacity is lower than the Net Cost of New Entry ( Net CONE, which reflects the cost of a new peaking unit net of contribution to investment costs obtained in energy and ancillary service markets). 7 As Figure 3 shows, deviations in procured capacity from target reliability requirements are also allowed within each LDA, where they are based on locational differences in relative capacity surplus after considering transmission system limitations. While several of the LDAs procured less capacity than the reliability target during the first four BRAs, total procurement has been greater than the target procurement in all constrained LDAs during the last three annual auctions, which covered delivery years 2011/12, 2012/13, and 2013/14. The prices at which these capacity resources were procured are shown in Figure 4. Capacity prices have varied substantially over the first seven delivery years as well as among the different LDAs. Importantly, however, the comparison of Figures 3 and 4 shows that the variances in capacity prices have been consistent with achieved reliability levels relative to reliability requirements. Capacity market prices have been low (relative to Net CONE) during times of capacity surplus, an outcome that will tend to postpone investments in new generation or delay the refurbishment of older units that require expensive upgrades. Similarly, capacity prices have been higher during times when capacity was more scarce, an outcome that incentivizes the development of new resources and the retention of existing resources. As Figure 4 documents, prices for the unconstrained portion of the RTO (in this context often simply referred to as RTO ) have generally been substantially below Net CONE and below prices observed in the constrained LDAs. These low RTO prices reflect capacity in excess of the resource adequacy target, as shown in Figure 3, due to excess capacity that existed in the RTO prior to RPM, large growth in demand response since RPM began, an increase in net imports from neighboring regions, capacity uprates in existing generation, and the retention of resources as discussed further below. As shown in Table 1 below, these factors have resulted in substantial increases in excess supply in the unconstrained RTO and, for planning year 2013/14, resulted in BRA capacity procurement of 104.4% of the reliability target with more than 8,000 MW of unforced capacity ( UCAP ) that was offered but did not clear in the auction. This substantial capacity surplus coincided with the low capacity price of $27.73/MW-day in that auction, compared to an RTO Net CONE of $317.95/MW-day More precisely, Net CONE is PJM s location-specific estimate of the annualized capital costs required to supply capacity in the market, net of profits received from energy and ancillary markets. Currently, PJM s Net CONE estimate is based on the estimated capital costs and operating revenues of a new combustion turbine. Auction prices will reach Net CONE when the sum of available resources drops to one percent above the target reserve margin that is determined based on PJM s reliability requirement (less a 2.5% hold-back for capacity to be procured in the later incremental auctions). Prices will rise above Net CONE when available resources fall below the target reserve margin plus one percent, minus the 2.5% holdback. PJM Base Residual Auction Parameters and Results for planning year 2013/14, Retrieved from 7

8 105% Figure 3 RPM BRA Cleared Capacity Relative to Reliability Target Cleared Capacity as Share of Reliability Threshold, % 104% 103% 102% 101% 100% 99% 98% RTO MAAC EMAAC SWMAAC DPL South PEPCO Capacity in Excess of Reliability Target Capacity Less than Reliability Target 97% 96% Delivery Year. 2007/ / / / / / /14 Auction Date... Apr 2007 Jul 2007 Oct 2007 Jan 2008 May 2008 May 2009 May 2010 Figure 4 BRA Clearing Prices by Locational Deliverability Area $300 RTO Net CONE Locational Capacity Price, $/MW-day & $250 $200 $150 $100 EMAAC SWMAAC SWMAAC Net CONE PEPCO DPL South MAAC $50 RTO Delivery Year. Auction Date / / / / / / /14 Apr 2007 Jul 2007 Oct 2007 Jan 2008 May 2008 May 2009 May 2010 Sources and Notes: PJM Base Residual Auction Parameters and Results. Excludes FRR capacity obligations and commitments. SWMAAC and MAAC values equal over 2010/ /14. SWMAAC was not separately modeled in 2011/12 and did not have a calculated Net CONE value. Reliability threshold as defined in Figure 3 is the reliability requirement less the Interruptible Load for Reliability ( ILR ) obligation for years prior to 2012/13 or less the 2.5% short-term resource procurement target for years starting 2012/13. 8

9 Capacity market prices are higher than the RTO-wide price in several of the LDAs, including recently in MACC, SWMAAC, DPL South, and PEPCO. These higher prices are associated with more constrained resources adequacy conditions (e.g., an absence of excess capacity) within these LDAs. Local and regional transmission constraints both contribute to these LDA resource fundamentals. 9 For example, Figure 4 shows that during the first three Base Residual Auctions, SWMAAC cleared at prices above Net CONE, consistent with the tight SWMAAC supply conditions shown in Figure 3 and the absence of sizable capacity resources that were offered but did not clear in the auctions as shown in Table 1. Starting with the auction for the 2011/12 planning year, however, SWMAAC has had a modest capacity surplus driven partly by demand response resources which increased from 20 MW in 2007/08 to 1,650 MW in 2013/14. This has resulted in approximately MW of SWMAAC generation resources that were offered but failed to clear in these auctions. The modest capacity surplus in SWMAAC in the last several auctions has also meant that the LDA has not price-separated from the larger MAAC region. Over the course of the last several auctions, however, factors that included projected load growth and the announced retirement of existing generating units, have reduced the capacity surplus in MAAC and SWMAAC, resulting in correspondingly increasing market prices for capacity in these locations. The levels and trends in capacity prices for other LDAs, such as EMAAC, DPL South and PEPCO, are similarly consistent with the levels and trends of resource availability relative to reliability targets. In summary, examining the capacity prices in the RTO and each constrained LDA reveals that they have demonstrated a pattern that is consistent with the relative surplus or scarcity of resources in each location. The most recent 2013/14 auction price results should not be examined in isolation, but within the context of trends in the overall supply-demand fundamentals, including locational resource availability relative to reliability targets. As the capacity surplus in MAAC and EMAAC has declined in the most recent auctions, the LDAs capacity prices have risen to levels approaching Net CONE. Given PJM s reliability requirements, this is an efficient outcome that will be important for signaling suppliers to get ready to invest in additional capacity resources in upcoming years. 9 Note that for SWMAAC, the transmission limitations that affect available supply are both limits on transmission capability into SWMAAC from the larger MAAC LDA region, as well as the transmission limits from the unconstrained RTO into MAAC. Similarly, DPL South is a constrained subzone of EMAAC, which is itself a constrained subzone of MAAC. This complexity in the transmission system makes resource adequacy both a local and regional issue. 9

10 Table 1 Cleared and Uncleared Capacity Resources by LDA Capacity, by Delivery Year (UCAP MW) 2007/ / / / / / /14 TOTAL RTO Total Cleared 129, , , , , , ,743 Cleared Generation (Including Imports) 129, , , , , , ,782 Cleared Demand Response ,365 7,047 9,282 Cleared Energy Efficiency Total Uncleared Capacity 1,435 2,283 1, ,499 9,230 8,155 Uncleared Generation (Including Imports) 1,435 2,103 1, ,211 6,346 4,407 Uncleared Demand Response ,800 3,671 Uncleared Energy Efficiency MAAC Total Cleared 60,476 60,707 63,010 63,327 61,603 65,452 67,640 Cleared Generation 60,411 60,230 62,268 62,419 60,559 60,549 61,617 Cleared Demand Response ,045 4,724 5,871 Cleared Energy Efficiency Total Uncleared 557 1, ,979 2, Uncleared Generation 557 1, ,823 2, Uncleared Demand Response Uncleared Energy Efficiency EMAAC Total Cleared 30,782 30,214 31,622 30,787 29,365 31,080 32,835 Cleared Generation 30,737 30,045 31,250 30,480 29,133 29,422 30,350 Cleared Demand Response ,638 2,461 Cleared Energy Efficiency Total Uncleared 29 1, ,670 1, Uncleared Generation ,594 1, Uncleared Demand Response Uncleared Energy Efficiency SWMAAC Total Cleared 10,201 10,621 9,915 10,873 10,780 11,595 11,242 Cleared Generation 10,182 10,312 9,558 10,354 10,039 9,661 9,482 Cleared Demand Response ,774 1,650 Cleared Energy Efficiency Total Uncleared Uncleared Generation Uncleared Demand Response Uncleared Energy Efficiency PEPCO Total Cleared 5,019 5,125 4,686 5,498 5,664 n/a 4,792 Cleared Generation 5,014 5,093 4,621 5,464 5,519 n/a 4,209 Cleared Demand Response Cleared Energy Efficiency Total Uncleared n/a 497 Uncleared Generation n/a 497 Uncleared Demand Response Uncleared Energy Efficiency Sources and Notes: PJM Base Residual Auction Reports. Monitoring Analytics' Analysis of RPM Base Residual Auction Results. 2007/ /11 BRA data provided by PJM. PEPCO cleared and uncleared generation data are unavailable for 2012/13. 10

11 IV. RPM HAS ATTRACTED AND RETAINED SUBSTANTIAL CAPACITY RESOURCES AT PRICES AT OR BELOW THE COST OF NEW GENERATION We found in our 2008 review that the auctions for the first five planning years under RPM have allowed PJM to attract and retain approximately 14,500 MW of installed capacity ( ICAP ). A substantial portion of this capacity, which is reasonably attributable to RPM, has been attracted and retained within constrained LDAs. For example, in SWMAAC approximately 1,750 MW of resources were attracted or retained through 2011/12. The breakdown of these resources is shown in Figure 5. In SWMAAC, most of these incremental resources were from demand response resources and the deferred retirements of aging units. In EMAAC and the RTO overall, substantial incremental capacity was also added through capacity uprates of existing power plants, withdrawn deactivation requests, and new generation. Figure 5 also shows that retained and attracted capacity amounted to 12% and 13% of peak load in SWMAAC and EMAAC respectively, exceeding the RTO-wide level of 10% of peak load. Since that review in 2008, the total capacity supplied from demand response and energy efficiency have increased substantially in each location as shown in Table 1 (above). 10 These sustained increases in low-cost supply from DR and uprates to existing generation have kept capacity prices below the net cost of a new peaking plant (i.e., Net CONE). In some cases, these new capacity resources have been committed at prices even below the cost of refurbishing some of the aging existing generation units. The result is that in the most recent auctions several aging units have failed to clear, resulting in approximately 790 MW (ICAP) of announced retirements (i.e., currently pending deactivation requests ) in SWMAAC and almost 2,700 MW of announced retirements in MAAC overall. 11 As we have shown in the 2008 RPM report, the capacity payments available through RPM not only facilitate the entry of new demand response and generation resources, but they are also critical to the retention of existing resources. Without these payments, several thousand additional MW of aging generating units would be at risk for retirement in both SWMAAC and EMAAC. The substantial increases in net capacity under RPM, especially from demand response, energy efficiency, and capacity uprates have occurred at capacity prices below Net CONE. This outcome has benefitted customers by reducing the overall costs of supply and postponing the need for investments in new, more expensive generating capacity that would otherwise have been required to meet reliability targets. However, as the decline of committed resources relative to reliability requirements in most recent RPM auctions has shown, additional internal capacity resources or transmission capability into some of the eastern LDAs (such as PEPCO) may be necessary soon after 2014 to avoid resource balances that are below reliability targets Table 1 shows an increase in demand response and energy efficiency of 1,020 UCAP MW in SWMAAC, 2,254 UCAP MW in EMAAC, and 8,596 MW for the RTO between 2011/12 and 2013/14. The SWMAAC pending deactivation requests are Benning 15 and 16, Buzzard Point East Banks 1, 2, 4-8, and Buzzard Point West Banks 1-8. Most of the other pending deactivation requests in MAAC have been submitted in EMAAC. See PJM Future Deactivations, August 27, Retrieved from 11

12 Figure 5 Added Resources and RPM-Retained Capacity in PJM, EMAAC, and SWMAAC (End of 2006 through 2011/12 Delivery Year) 16,000 14,552 MW (10% Peak Load) Uncleared Incremental Capacity Increase in Capacity, ICAP MW 14,000 12,000 10,000 8,000 6,000 4,000 2, ,000-4,000 Net 1,762 MW (12% Peak Load) Incremental CETL from 2007/08 to 2010/11 4,517 MW (13% Peak Load) Incremental CETL from 2007/08 to 2009/10 SWMAAC EMAAC Total RTO Projected ILR Increases DR Increases Net Export Decreases Net Capacity Additions Rating Changes Withdrawn Deactivation Requests Other Planned Retirements Cancelled or Deferred Existing Units Fully Uncleared in 2011/12 Source: Brattle analysis of PJM data, market participant interviews. V. STABILITY IN THE RPM MARKET DESIGN IS IMPORTANT TO AVOID ADVERSE IMPACTS ON INVESTMENT The RPM capacity market has a demonstrated history of setting appropriate market-based capacity prices and ensuring reliability at an appropriate location-specific level. These price signals must continue to be consistent with market conditions over the long term in order to attract and retain capacity at reasonable costs in the long-run. In order to achieve this goal, stability in the market design is important. Refinements to the market design will be desirable to continue increasing market efficiency and enable robust competition, including from DR and other supply. Large market design changes or regulatory interventions are undesirable, however, because they increase the regulatory risks associated with participating in the market. In the worst case, substantial market design changes could undermine efficient market-based price signals and investors willingness to fund needed capital additions. In an efficient market, these capacity price signals will be higher than the cost of new resources during times of capacity shortage and lower during capacity surplus. Regulatory intervention in response to rising prices would signal to investors that sufficient returns on investment cannot be realized even during times of scarcity. This type of intervention would undermine confidence in the market and result in higher required returns on investment, thereby resulting in lower reliability and increased costs to consumers in the long run. 12

13 We recommend that possible improvements to RPM be evaluated carefully and be approached with a long-term perspective to ensure the efficient evolution of the regional electricity market. As pointed out in our 2008 RPM review with respect to the LDAs in eastern PJM, which include Maryland, some possible improvements should be evaluated to determine whether they might improve market efficiency and possibly price stability. Some of these possible improvements include a reevaluation of the new-entry pricing mechanism, and a reevaluation of how LDA reliability requirements and local constraints are determined and modeled in the auctions, which have also contributed to the observed changes in LDA capacity prices. 13

14 Commenters Certification We hereby certify that we have prepared or supervised the preparation of the filing signed and know its contents are true as stated to the best of our knowledge and belief. We possess full power and authority to sign this filing. Respectfully Submitted, Johannes Pfeifenberger Principal The Brattle Group 44 Brattle Street Cambridge, MA Kathleen Spees Associate The Brattle Group 44 Brattle Street Cambridge, MA Attachment A Attachment B Attachment C Attachment D Qualifications of Johannes P. Pfeifenberger Qualifications of Kathleen Spees Pfeifenberger, J., S. Newell, R. Earle, A. Hajos, and M. Geronimo. Review of PJM s Reliability Pricing Model (RPM). June 30, Pfeifenberger, J., K. Spees, and A. Schumacher. A Comparison of PJM s RPM with Alternative Energy and Capacity Market Designs. September Dated October 1, 2010 Copyright 2011 The Brattle Group, Inc. 14