Analysis of the 2012/2013 RPM Base Residual Auction

Transcription

1 Analysis of the 2012/2013 RPM Base Residual Auction The Independent Market Monitor for PJM August 6, 2009 Monitoring Analytics

2 Introduction This report, prepared by the Independent Market Monitor for PJM (IMM or MMU), reviews the functioning of the seventh Reliability Pricing Model (RPM) auction (for the 2012/2013 delivery year) and responds to questions raised by PJM members and market observers about that auction. The MMU prepares a report for each RPM auction. This report addresses, explains and quantifies the basic market outcomes. This report also addresses and quantifies the impact on market outcomes of: the VRR curve; constrained LDAs; EFORd rule changes; the short term resource procurement target; the increased default ACR rates; the mitigation of Demand Resources; Demand Resources. The capacity market is, by design, always tight in the sense that total supply is generally only slightly larger than demand. While the market may be long at times, that is not the equilibrium state. Capacity in excess of demand is not sold and, if it does not earn or does not expect to earn adequate revenues in other markets or does not have value as a hedge, may be expected to retire. The demand for capacity includes expected peak load plus a reserve margin. Thus, the reliability goal is to have total supply equal to or slightly above the demand for capacity. Demand is almost entirely inelastic because the market rules require loads to purchase their share of the system capacity requirement. The level of elasticity built into the RPM demand curve, called the variable resource requirement (VRR) curve, is not adequate to modify this conclusion. The result is that any supplier that owns more capacity than the typically small difference between total supply and the defined demand is pivotal and therefore has structural market power. The market design for capacity leads, almost unavoidably, to structural market power in the capacity market. The capacity market is unlikely ever to approach a competitive market structure in the absence of a substantial and unlikely structural change that results in much greater diversity of ownership. Nonetheless a competitive outcome can be assured by appropriate market power mitigation rules. Detailed market power mitigation rules are included in the RPM tariff. This represents a significant advance over the prior capacity market design. Reliance on the RPM design for competitive outcomes means reliance on the market power mitigation rules. Attenuation of those rules would mean that market participants would not be able to rely on the competitiveness of the market outcomes. In the capacity market, as in other markets, market power is the ability of a market participant to increase the market price above the competitive level or to decrease the market price below the competitive level. In order to evaluate whether actual prices reflect the exercise of market power, it is necessary to evaluate the competitive market offers. Recent changes to the rules for the RPM auctions address the treatment of historical equivalent demand forced outage rates (EFORd) in determining the level of unforced Monitoring Analytics

3 capacity that must be offered. These changes include the elimination of EFORd risk segments from offers and the addition of a corresponding option to submit unforced capacity based on an EFORd up to the greater of the EFORd based on 12 months of outage data ending September 30 prior to the auction or the EFORd based on five years of data ending on September 30 prior to the auction. Under the previous rules, participants were required to submit unforced capacity based on an EFORd less than or equal to the EFORd based on 12 months of outage data. 1 Effective for the 2012/2013 planning year, the load management product Interruptible Load for Reliability (ILR) was eliminated. It was replaced by the short term resource procurement target. In prior Base Residual Auctions (BRA), PJM subtracted the ILR forecast from the reliability requirement. Under the current rules, 2.5 percent of the reliability requirement is removed from the demand curve. The ILR adjustment was equivalent to removing 1.2 percent of the reliability requirement in the 2011/2012 BRA. The stated rationale for this administrative reduction in demand in the BRA is to permit short lead time resource procurement in later auctions for the delivery year. The Energy Efficiency (EE) resource type was eligible to be offered in RPM auctions for the first time for the 2012/2013 delivery year. The MMU verified the reasonableness of offer data and calculated the derived offer caps based on submitted data, calculated unit net revenues, verified capacity exports, verified the reasons for MW not offered, verified the maximum EFORd rates used, verified clearing prices based on the demand curves and verified that the market structure tests were applied correctly. All participants in the RTO as well as MAAC, PSEG North, and DPL South RPM markets failed the three pivotal supplier (TPS) test. All participants included in the incremental supply of EMAAC passed the test. The result was that offer caps were applied to all sell offers of participants that did not pass the test, excluding sell offers for new units. The offer caps are designed to reflect the marginal cost of capacity. Based on these facts, the MMU concludes that the results of the 2012/2013 RPM Base Residual Auction were competitive. Under the tariff, PJM determines, in advance of each BRA, whether defined Locational Deliverability Areas (LDAs) may be constrained in the auction. Under the rules in effect for the 2011/2012 BRA, an LDA with a Capacity Emergency Transfer Limit (CETL) greater than 1.05 times the Capacity Emergency Transfer Objective (CETO) was not permitted to constrain in the auction. That CETL to CETO ratio test of 1.05 was too restrictive and prevented significant locational price differences from occurring in the 2011/2012 base residual auction. Another recent change to the rules increased the CETL FERC 61,275 (2009). Monitoring Analytics

4 to CETO threshold ratio used to determine the modeled LDAs for the 2012/2013 delivery year from 1.05 to The rules also provide that regardless of the test results, separate VRR curves will be established for any LDA with a locational price adder in one or more of the three immediately preceding BRAs, any LDA that PJM determines in a preliminary analysis is likely to have a locational price adder based on historic offer price levels, and EMAAC, SWMAAC, and MAAC LDAs. Table 1 shows the clearing prices by LDA compared to the corresponding Net CONE values. The clearing prices were less than Net CONE for each LDA except DPL South. Table 1 Clearing prices and net CONE LDA Clearing Price ($/MW-day) Net CONE ($/MW-day) RTO $16.46 $ MAAC $ $ EMAAC $ $ PSEG North $ $ DPL South $ $ Preliminary Market Structure Screen Under the terms of the PJM Tariff, the MMU is required to apply the preliminary market structure screen (PMSS) prior to RPM Base Residual Auctions. 3 The purpose of the PMSS is to determine whether additional data are needed from owners of capacity resources in the defined areas in order to permit the MMU to apply the market structure tests defined in the Tariff. For each LDA and the PJM Region, the PMSS is based on: (1) the unforced capacity available for the delivery year from generation capacity resources located in such area; and (2) the LDA s reliability requirement and the PJM reliability requirement. 4 An LDA or the Regional Transmission Organization (RTO) region fails the PMSS if any one of the following three screens is failed: (1) the market share of any capacity resource owner exceeds 20 percent; (2) the Herfindahl Hirschman Index (HHI) for all capacity resource owners is 1800 or higher; or (3) there are not more than three jointly pivotal FERC 61,275 (2009). 3 See PJM Open Access Transmission Tariff (OATT), Attachment DD: Reliability Pricing Model, Substitute Original Sheet No. 605 (Effective June 1, 2007), section 6.3 (a) (i). 4 The terms PJM Region, RTO Region and RTO are synonymous in this report and include all capacity within the PJM footprint. Monitoring Analytics

5 suppliers. 5 Capacity resource owners who own or control generation in the area that fails the PMSS are required to provide avoidable cost rate (ACR) data to the MMU. 6 Consistent with the requirements of the Tariff, the MMU applied the PMSS two months prior to the 2012/2013 RPM Base Residual Auction. As shown in Table 2, all LDAs and the entire PJM Region failed the PMSS. The RTO and MAAC passed the market share and HHI screens, but failed the three pivotal supplier screen. As a result, capacity resource owners were required to submit ACR data to the MMU for resources for which they intended to submit non zero sell offers unless certain other conditions were met. 7 There were no provisional exceptions for the 2012/2013 Auction. Table 2 Preliminary Market Structure Screen results: 2012/2013 RPM Markets Highest Market Share HHI Pivotal Suppliers Pass/Fail RTO 17.4% Fail MAAC 17.6% Fail EMAAC 32.8% Fail SWMAAC 50.7% Fail PSEG 84.3% Fail PSEG North 90.9% Fail DPL South 55.0% Fail Offer Caps The defined capacity resource owners were required to submit ACR data to the MMU by six weeks prior to the 2012/2013 RPM Base Residual Auction. If a capacity resource owner failed the market power test for the auction, avoidable costs less PJM market revenues, or opportunity costs were used to calculate offer caps for that owner s resources. 5 See PJM Open Access Transmission Tariff (OATT), Attachment DD: Reliability Pricing Model, Original Sheet No. 605A (Effective June 1, 2007), section 6.3 (a) (ii). 6 See PJM Open Access Transmission Tariff (OATT), Attachment DD: Reliability Pricing Model, Third Revised Sheet No. 610 (Effective March 27, 2009). The required data are defined at section See PJM Open Access Transmission Tariff (OATT), Attachment DD: Reliability Pricing Model, Third Revised Sheet No. 610 (Effective March 27, 2009), section 6.7 (c). Monitoring Analytics

6 Avoidable costs are the costs that a generation owner would not incur if the generating unit did not operate for one year, in particular the delivery year. 8 In effect, avoidable costs are the costs that a generation owner would not incur if the generating unit were mothballed for the year. In the calculation of avoidable costs, there is no presumption that the unit would retire as the alternative to operating, although that possibility could be reflected if the owner documented that retirement was the alternative. Avoidable costs also include annual capital recovery associated with investments required to maintain a unit as a capacity resource. Avoidable costs are defined to be net of net revenues from all other PJM markets and unit specific bilateral contracts. The specific components of avoidable costs are defined in the PJM Tariff. Capacity resource owners could provide ACR data by providing their own unit specific data, by selecting the default ACR values or by submitting an opportunity cost for a possible export or a potential import. The default ACR values for both the mothball and the retirement options were calculated by the MMU based on available unit data, posted to the Monitoring Analytics Web site and included in the tariff, in order to provide an alternative for owners that did not wish to calculate unit specific ACR values or who believed that the default ACR values exceeded their unit specific ACR values. The opportunity cost option allows resource owners to input a documented export opportunity cost as the offer for the unit. If the relevant RPM market clears above the opportunity cost, the unit s capacity is sold in the RPM market. If the opportunity cost is greater than the clearing price, the unit s capacity does not clear in the RPM market and it is available for export. Effective with this auction, ACR default rates were increased. As shown in Table 3, 1,133 generating resources submitted offers compared to 1,125 generating resources offered in the 2011/2012 RPM Base Residual Auction. The net increase of eight resources consisted of 16 new resources (772.5 MW), four resources that were previously entirely Fixed Resource Requirement (FRR) committed (13.4 MW), three additional resources imported (276.8 MW), two additional resources resulting from disaggregation of RPM resources, and one resource formerly unoffered (1.9 MW), offset by nine retired resources (1,044.5 MW), four additional resources committed fully to FRR (39.5 MW), four less resources resulting from aggregation of RPM resources, and one less external resource that did not offer (663.2 MW). 9 In addition, there were the 8 See PJM Open Access Transmission Tariff (OATT), Attachment DD: Reliability Pricing Model, First Revised Sheet No. 617 (Effective January 19, 2008), section 6.8 (b). 9 Disaggregation and aggregation of RPM resources reflect changes in how units are offered in RPM. For example, multiple units at a plant may be offered as a single unit or multiple units. Monitoring Analytics

7 following retirements of resources that were either exported or excused in the 2011/2012 BRA: two combustion turbine resources (5.3 MW) and three combined cycle resources (297.6 MW). Also, resources that are no longer PJM capacity resources consisted of three CT units (521.5 MW) in the RTO. The publicly posted future deactivation requests include Hudson 1 (159.5 MW) in PSEG North; Benning 15 (233.8 MW), Benning 16 (233.8 MW), Buzzard Point CT East (100.8 MW), and Buzzard Point CT West (115.2 MW) in MAAC; and Will County Coal 1 (133.4 MW) and Will County Coal 2 (142.5 MW) in RTO. In addition, resources that are no longer capacity resources but do not have public notifications of future deactivations consisted of two CT resources (185.5 MW) in PSEG North; one CT resource (1.1 MW), one diesel resource (5.5 MW), one steam unit (10.4 MW), and one combined cycle resource (21.7 MW) in EMAAC; and one CT (4.2 MW) in MAAC. The new units consisted of six new diesel resources (13.9 MW), four new wind resources (57.9 MW), three new steam units (560.4 MW), two new CT units (85.2 MW), and one new combined cycle unit (55.1 MW). 10 There were 233 demand resources (DR) offered compared to 37 DR resources offered in the 2011/2012 RPM Base Residual Auction. There were 53 Energy Efficiency (EE) resources offered as a new resource type for the 2012/2013 planning year. The MMU calculated 610 offer caps, of which 479 were based on the technology specific default (proxy) ACR values calculated by the MMU. 11 Unit specific offer caps were calculated for 120 units (10.6 percent) including 118 units (10.4 percent) with an Avoidable Project Investment Recovery Rate (APIR) component and 2 units (0.2 percent) without an APIR component. Owners submitted unit specific cost data, the MMU calculated net revenue data for these units, and the MMU calculated the unit specific offer caps based on that data. Of the 1,133 generating units, 11 new resources had uncapped offers while the remaining 515 generating resources were price takers, of which the offers for 512 resources were zero and the offers for three resources were set to zero because no data were submitted. 12 As shown in Table 4, the weighted average gross ACR for units with APIR ($ per MW day) and the weighted average offer caps, net of net revenues, for units with APIR ($ per MW day) increased from the 2011/2012 values of $ per MW day and $ per MW day, respectively, due to higher ACRs for subcritical/supercritical coal 10 Unless otherwise specified, all volumes and prices are in terms of UCAP. 11 Three resources had both ACR based and opportunity cost based offer caps calculated. 12 Planned units are subject to mitigation only under specific conditions defined in the tariff. Some of the 11 uncapped planned units submitted zero price offers. See PJM Open Access Transmission Tariff (OATT), Attachment DD: Reliability Pricing Model, Substitute Second Revised Sheet No. 607 (Effective March 27, 2009), section 6.5 (a) ii. Monitoring Analytics

8 and CC units with APIR. Offer caps for units without an APIR component, including units for which the default value was selected, decreased from $45.80 per MW day to $21.55 per MW day due to lower submitted opportunity costs and higher net revenues for CC and CT units. 13 The APIR component added $ per MW day to the ACR value of the APIR units compared to $ per MW day in 2011/ ,15 The default ACR values include an average APIR of $1.31 per MW day compared to $0.91 per MWday in the 2011/2012 BRA. The highest APIR for a technology ($ per MW day) was for subcritical/supercritical coal units. The maximum APIR effect ($1, per MWday) is the maximum amount by which an offer cap was increased by APIR. 13 The 2011/2012 APIR statistics were revised since the 2011/2012 BRA report was posted. 14 The net revenue offset for an individual unit could exceed the corresponding ACR. In that case, the offer cap would be zero. 15 The 118 units which had an APIR component submitted $567.2 million for capital projects associated with 11,124.8 MW of UCAP. Monitoring Analytics

9 Table 3 ACR statistics: 2012/2013 RPM Base Residual Auction 16 Percent of Generation Calculation Type Number of Resources Resources Offered Default ACR selected % ACR data input (APIR) % ACR data input (non-apir) 2 0.2% Opportunity cost input 8 0.7% Default ACR and opportunity cost input 3 0.3% Generating resources with offer caps % Uncapped new generation resources % Generation price takers % Generation resources offered 1, % Capped existing demand resources 163 Uncapped planned demand resources 38 Demand resources with existing and planned portions 32 Demand resources offered 233 Uncapped energy efficiency resources 53 Energy efficiency resources offered 53 Total capacity resources offered 1, The classification of DR resources as planned includes only DR resources that offered planned MW at non zero sell offer prices; it does not include planned DR MW that were offered at $0 per MW day. Monitoring Analytics

10 Table 4 APIR statistics: 2012/2013 RPM Base Residual Auction 17 Combined Cycle Combustion Turbine Weighted-Average ($ per MW-day UCAP) SubCritical/ Oil or Gas Steam SuperCritical Coal Other Opportunity Costs Total Non-APIR units ACR $41.84 $32.61 $75.47 $ $57.18 $ Net revenues $91.67 $35.29 $7.51 $ $ $ Offer caps $5.28 $14.40 $67.96 $11.31 $15.63 $ $21.55 APIR units ACR $ $49.83 $ $ N/A $ Net revenues $98.97 $15.62 $3.62 $ N/A $ Offer caps $ $34.96 $ $ N/A $ APIR $ $26.59 $89.08 $ N/A $ Maximum APIR effect $1, RPM Auction Results MMU Methodology The MMU reviewed the following inputs to and results of the 2012/2013 RPM auction: 18 Offer Cap Verified that the avoidable costs, opportunity costs and net revenues used to calculate offer caps were reasonable and properly documented; Net Revenues Calculated actual unit specific net revenue from PJM energy and ancillary service markets for each PJM capacity resource for the period from 2006 through 2008; Exported Resources Verified that capacity resources exported from PJM had firm external contracts or made documented opportunity cost offers; Excused Resources Verified the specific reasons that capacity resources were excused from offering into the auction; 17 The weighted average offer cap can be positive even when the weighted average net revenues are higher than the weighted average ACR because the unit specific offer caps are never less than zero. On a unit basis, if net revenues are greater than ACR the offer cap is zero. 18 All volumes and prices are in terms of unforced capacity (UCAP), which is calculated as installed capacity (ICAP) times (1 EFORd). The EFORd values in this report are the EFORd values used in the 2012/2013 RPM Base Residual Auction. Monitoring Analytics

11 Maximum EFORd Verified that the sell offer EFORd levels were less than or equal to the greater of the one year EFORd or the five year EFORd for the period ending September 30, 2008; Clearing Prices Verified that the auction clearing prices were accurate, based on submitted offers and the VRR curves; Market Structure Test Verified that the market power test was properly defined using the TPS test, that offer caps were properly applied and that the TPS test results were accurate. Market Structure Tests Only those participants that fail the market power test are subject to offer capping. As shown in Table 5, all participants in the RTO as well as MAAC, PSEG North, and DPL South RPM markets failed the TPS test. 19 All participants included in the incremental supply of EMAAC passed the test. The result was that offer caps were applied to all sell offers of participants that did not pass the test, excluding sell offers for new units. The RTO market includes all supply. The constrained LDA markets include the incremental supply inside the constrained LDAs which was offered at a price higher than the unconstrained clearing price for the parent LDA market. The incremental demand consists of the MW needed inside the LDA to relieve the constraint. Incremental demand in EMAAC was 18.6 MW. The incremental supply in EMAAC, considered in the application of the three pivotal supplier test, was MW, including all offered MW with sell offer prices greater than the MAAC clearing price of $ per MW day and less than or equal to 1.5 times the EMAAC clearing price of $ per MW day. There were six parent companies in EMAAC with incremental supply resources. One company supplied the 18.6 MW needed to meet the incremental demand, all of which were DR resources. Table 5 presents the results of the TPS test. A generation owner or owners are pivotal if the capacity of the owners generation facilities is needed to meet the demand for capacity. The results of the TPS are measured by the Residual Supply Index (RSIx). The RSIx is a general measure that can be used with any number of pivotal suppliers. The subscript denotes the number of pivotal suppliers included in the test. If the RSIx is less than or equal to 1.0, the supply owned by the specific generation owner, or owners, is needed to meet market demand and the generation owners are pivotal suppliers with a 19 See the 2008 State of the Market Report for PJM, Volume II, Section 2, Energy Market, Part 1, and Volume II, Appendix L, Three Pivotal Supplier Test for a more detailed discussion of market structure tests. Monitoring Analytics

12 significant ability to influence market prices. If the RSIx is greater than 1.0, the supply of the specific generation owner or owners is not needed to meet market demand and those generation owners have a reduced ability to unilaterally influence market price. 20 MAAC/SWMAAC are presented together because SWMAAC was modeled but was not a constrained LDA in this auction. Similarly, EMAAC/PSEG are presented together because PSEG was modeled but was not a constrained LDA in this auction. Table 5 RSI Results: 2012/2013 RPM Base Residual Auction RSI RSI 3 Participants Total Failed RSI 3 Participants RTO MAAC/SWMAAC EMAAC/PSEG PSEG North DPL South RTO Table 6 shows total RTO offer data for the 2012/2013 RPM Base Residual Auction. All MW values stated in the RTO section include all nested LDAs. Nested LDAs occur when a constrained LDA is a subset of a larger constrained LDA or the RTO. For example, MAAC is nested in the RTO as all other LDAs. As another example, EMAAC, PSEG North and DPL South are all nested in MAAC. Total internal RTO unforced capacity increased 10,070.6 MW (6.3 percent) from 159,882.7 MW in the 2011/2012 RPM BRA to 169,953.3 MW as a result of new generation (772.5 MW), capacity upgrades to existing generation and increases in DR and EE, net of derations to existing generation and demand capacity resources. As shown in Table 7, of the 10,070.6 MW increase, 3,187.2 MW were due to the reclassification of the Duquesne zone to internal, MW were net generation capacity modifications (cap mods), 8,028.7 MW were net DR modifications (DR mods), and MW were the newly offered EE resource. 21 A decrease of MW (0.59 percent) was due to higher sell offer EFORds, and the remaining decrease of 1.9 MW was due to a lower Load Management UCAP conversion 20 The market definition used for the TPS test includes all offers with costs less than or equal to 1.50 times the clearing price. The appropriate market definition to use for the one pivotal supplier test includes all offers with costs less than or equal to 1.05 times the clearing price. See 2008 State of the Market Report for PJM (March 11, 2009), Appendix L, Three Pivotal Supplier Test for additional discussion. 21 Similar to cap mods for generation resources, DR mods include modifications (increases/decreases) to existing DR and the creation of new planned DR. Monitoring Analytics

13 factor compared to the 2011/2012 BRA. 22, 23 Total internal RTO unforced capacity includes all generating units, DR, and EE that qualified as PJM capacity resources for the 2012/2013 auction, excluding external units, and also includes owners modifications to installed capacity ratings which are permitted under the PJM Reliability Assurance Agreement (RAA) and associated manuals. 24 The ICAP of a unit may only be reduced through a cap mod if the capacity owner does not intend to restore the reduced capability by the end of the planning period following the planning period in question. 25 Otherwise the owner must take an outage, as appropriate, if the owner cannot provide energy consistent with the ICAP of the unit. Multiple owners submitted both positive and negative capacity modifications, with a net RTO increase of 7,154.8 MW of ICAP and 7,829.4 MW of UCAP (Table 7 and Table 8). Cap mod increases and decreases were the result of owner reevaluation of the capabilities of their generation and DR, at least partially in response to the incentives and penalties contained in RPM. After accounting for FRR committed resources and for imports, RPM capacity was 149,520.1 MW compared to 142,263.1 MW in the 2011/2012 RPM Base Residual Auction. 26 FRR volumes increased by MW, and imports 22 The UCAP value of a load management product is equal to the ICAP value multiplied by the Demand Resource Factor and the Forecast Pool Requirement (FPR). For the 2011/2012 BRA, this conversion factor was 0.955* = For the 2012/2013 BRA, this factor was.950* = The Demand Resource Factor is designed to reflect the difference in losses that occur on the distribution system between the meter where demand is measured and the transmission system. The FPR multiplier is designed to recognize the fact that when demand is reduced by one MW, the system does not need to procure that MW or the associated reserve. 23 See PJM Manual 20: PJM Resource Adequacy Analysis, Revision 03 (June 1, 2007), p Hhttp:// (662.9 KB). 24 See Reliability Assurance Agreement among Load Serving Entities in the PJM Region, (June 1, 2007) (Accessed May 20, 2009) < (1.92 MB). 25 See PJM Manual 21: Rules and Procedures for Determination of Generating Capability, Revision 05 (June 1, 2008), p. 11 < ( KB). The manual states the end of the next planning period. 26 The FRR alternative allows an LSE, subject to certain conditions, to avoid direct participation in the RPM auctions. The LSE is required to submit an FRR capacity plan to satisfy the unforced capacity obligation for all load in its service area. Monitoring Analytics

14 decreased by 2,588.4 MW. RPM capacity was reduced by exports of 2,637.1 MW and 44.2 MW which were excused from the RPM must offer requirement as a result of planned reductions due to environmental regulations (34.5 MW) and other factors (9.7 MW). Exports decreased MW, and excused volumes decreased MW from the 2011/2012 RPM auction. Subtracting 1,465.5 MW of FRR optional volumes not offered, an increase of MW in FRR MW not offered from the 2011/2012 RPM Base Residual Auction, resulted in 145,373.3 MW that were available to be offered into the auction, an increase of 7,653.0 MW. 27 After accounting for the above, all capacity resources were offered into the RPM auction. As shown in Figure 1, the resource clearing price for the RTO was $16.46 per MW day. As shown in Figure 4, the RTO clearing price decreased from $ per MW day in the 2011/2012 Base Residual Auction to $16.46 per MW day in the 2012/2013 auction. The RTO clearing price decreased from $80.00 per MW day, using the price calculated by the MMU, accounting for economic LDA price separation. 28 Offered volumes increased 7,653.0 MW from 137,720.3 MW to 145,373.3 MW, while the overall RTO reliability requirement, from which the demand curve is developed, increased 3,073.7 MW from 130,658.7 MW to 133,732.4 MW. 29 The increase in the reliability requirement, due to the inclusion of the Duquesne control zone in the preliminary forecast peak load, shifted the RTO market demand curve to the right. As shown in Table 6, the net load price that LSEs will pay is $16.46 per MW day in the RTO. The final zonal capacity price will be calculated after the third incremental auction if no conditional incremental auctions are held. 27 FRR entities are allowed to offer into the RPM auction excess volumes above their FRR quantities, subject to a sales cap amount. The 1,465.5 MW are a combination of excess volumes included in the sales cap amount which were not offered into the auction and volumes above the sales cap amount which were not permitted to offer into the auction. 28 See Analysis of the 2011/2012 RPM Auction (Revised October 1, 2008) < Hhttp:// review of rpm auction revised.pdf > 29 The demand curve UCAP quantities are based on three points, which are ratios of the installed reserve margin (IRM = 16.2 percent) times the reliability requirement, less the forecast RTO ILR obligation. For the three points, the ratios are 1.132/1.162, 1.172/1.162 and 1.212/ For these three points the UCAP prices are based on factors multiplied by net cost of net entry (CONE) divided by one minus the pool wide EFORd. Net CONE is defined as CONE minus the energy and ancillary service revenue offset (E&AS). For the three points, the factors are 1.5, 1.0 and 0.2. Monitoring Analytics

15 The Impact of the Downward Sloping Demand Curve on Cleared Prices and Quantities As a result of the downward sloping demand curve, more capacity cleared in the market than would have cleared with a vertical demand curve equal to the reliability requirement. As shown in Table 6, the 136,143.5 MW of cleared resources for the entire RTO, which represented a reserve margin of 20.9 percent, resulted in net excess of 5,754.4 MW over the reliability requirement of 133,732.4 MW (IRM of 16.2 percent). 30, 31 Net excess increased 2,597.8 MW from the net excess of 3,156.6 MW in the 2011/2012 RPM auction. As shown in Figure 1, the downward sloping demand curve resulted in a price of $16.46 per MW day. The 9,229.8 MW of uncleared volumes in the entire RTO were the result of offer prices which exceeded the clearing prices. Of the uncleared MW in the entire RTO, 83.8 MW were EE offers, 2,800.4 MW were DR offers, and the remaining 6,345.6 MW were generation offers. Table 9 presents details on the generation offers that did not clear. If the demand curve had been vertical at the reliability requirement less the short term resource procurement with the same maximum price set at 1.5 times the net Cost of New Entry (CONE) and the RTO cleared as a single market, the clearing price would have been $25.23 per MW day as shown in Figure 2. If the given LDAs were modeled and the demand curves had been vertical at the LDA reliability requirements less the LDA shortterm procurement targets, MAAC, DPL South, and PSEG North would have had binding constraints, and EMAAC, SWMAAC, and PSEG would not have had binding constraints. The RTO would have cleared at $0.05 per MW day as shown in Figure 3. The conclusion is that the use of downward sloping demand curves for the RTO and the individual LDAs had a significant impact on the clearing prices and quantities. The Price Impacts of Constraints in the RPM Market As is the case in locational energy markets, constraints in the PJM capacity markets affect clearing prices both by increasing prices in constrained areas and decreasing prices in unconstrained areas. Conversely, removing constraints reduces prices in constrained areas and increases prices in unconstrained areas. The impact on total market revenues depends on the relative sizes of the various markets as well as the shapes of the supply and demand curves in the various markets. This was illustrated by 30 Prior to the elimination of ILR, net excess under RPM was calculated as cleared capacity less the reliability requirement plus ILR. After the ILR forecast was replaced by the Short Term Resource Procurement Target, net excess under RPM is calculated as cleared capacity less the reliability requirement plus the Short Term Resource Procurement Target. 31 The IRM increased from 15.5 percent to 16.2 percent for the 2012/2013 delivery year. Monitoring Analytics

16 the difference in results for the 2011/2012 BRA between PJM, which did not incorporate any constraints, and the MMU, which did incorporate economic constraints. The impact of constraints on relative prices was even more significant in the 2012/2013 BRA. There were four binding constraints in the 2012/2013 BRA which resulted in demand clearing in those LDAs which did not clear in the RTO market. The result was to shift the demand curve in the RTO market to the left along the upwardly sloping supply curve and to reduce the price in the RTO market. The price impact is the result both of the size of the shift of the demand curve and the slope of the supply curve. The larger the shift in the demand curve and the steeper the slope of the supply curve, the greater the price impact. Figure 5 illustrates the impact of the constraints on relative prices in the 2012/2103 BRA. If no LDAs had been modeled in this auction and the RTO had cleared as a single market, the RTO would have cleared at $73.32 per MW day. If only PSEG North and DPL South had been modeled, the RTO would have cleared at $70.30 per MW day. If, in addition, EMAAC had been modeled, the RTO would have cleared at $53.67 MW day. Finally, adding MAAC as a constrained LDA results in the RTO market clearing at $16.46 per MW day. MAAC was the largest LDA in terms of cleared MW and had a correspondingly large impact on the clearing price in the RTO. If the market had cleared as a single market, total RPM market revenues for the 2012/2013 delivery year would have been $3,633,347,891. If only PSEG North and DPL South had been constrained, total RPM market revenues for the 2012/2013 delivery year would have been $3,701,633,882. If, in addition, EMAAC had been constrained, total RPM market revenues for the 2012/2013 delivery year would have been $3,738,888,715. Based on actual auction clearing prices and quantities, total RPM market revenues for the 2012/2013 delivery year were $3,783,207,927. Nested LDAs occur when a constrained LDA is a subset of a larger constrained LDA or the RTO. The supply and demand curves for nested LDAs can be presented in two different ways to illustrate the market clearing dynamic. The supply curves in the graphs in this report, unless otherwise noted, show total supply of the LDA, including all nested LDAs and not including CETL MW. The demand curve is reduced by the CETL and by what cleared incrementally in the constrained, nested LDAs. There is another way to describe the mechanics of the impact of constrained LDAs on the RTO market. Rather than shifting the demand curve in the RTO market to the left, the mechanics can be described as shifting the supply curve to the right by the amount of capacity cleared in the constrained LDAs plus the CETL amounts that med load in the constrained LDAs. This is the approach presented in the PJM report. In this approach, the demand curve is represented by the original VRR points. The result is the same. Note that this does not mean that the supply from the LDAs is literally offered at zero in Monitoring Analytics

17 the RTO market, but is simply a way to describe the mechanics of clearing locational markets. Mitigated and Unmitigated Supply Curves Figure 6 shows the RTO unmitigated and mitigated supply curves. The unmitigated supply curve includes all submitted offers while the mitigated supply curve includes the sell offers used in clearing the market. The two curves differ where an offer was reduced to an offer cap when an owner failed the TPS test. There were 48 mitigated DR resources, including 1,874.7 MW, and 39 mitigated generating resources, including 3,758.6 MW, for a total of 5,633.3 MW that cleared with mitigated offers. Composition of the Steeply Sloped Portion of the Supply Curve Table 10 shows the composition of the offers on the steeply sloped portion of the RTO supply curve (see Figure 1) from $35.00 per MW day up to and including the highest offer of $ per MW day. Offers based on opportunity costs made up 13.1 percent of the offers on this section of the supply curve while oil/gas steam, combustion turbines and coal units made up 66.9 percent of the offers, most with APIR. The last offer to clear in the RTO was for a CT unit without APIR. Impacts of Rule Changes Affecting EFORd Recent changes to the rules for the RPM auctions address the treatment of historical EFORd used in determining the level of unforced capacity that must be offered. These changes include the elimination of the EFORd risk segments and the addition of a corresponding option to submit unforced capacity based on an EFORd up to the greater of the EFORd based on 12 months of outage data ending September 30 prior to the auction or the EFORd based on five years of outage data ending on September 30 prior to the auction. Under the previous rules, participants were required to submit unforced capacity based on an EFORd less than or equal to the EFORd based on 12 months of outage data. 32 The EFORd offer segment was designed to address the risk of a change in EFORd between the auction and the delivery year. A participant could submit a sell offer where the sell offer price for the EFORd segment was no greater than the net CONE. The MW quantity in the EFORd segment could be no greater than the summer net capability ICAP times the positive difference between the five year EFORd and oneyear EFORd, or the positive difference between the EFORd reasonably anticipated for the 12 months ending on September 30 prior to the delivery year and the average EFORd for the 12 months ending on September 30 prior to the auction FERC 61,275 (2009). Monitoring Analytics

18 If participants had not been given the option to use the five year EFORd and had been required to use the one year EFORd, the result would have been more UCAP MW offered into the auction. The total internal RTO unforced capacity would have been 171,155.0 MW compared to the actual 169,953.3 MW, a difference of 1,201.7 MW. When comparing UCAP MW levels from one auction to another, two variables, capacity modifications and EFORd changes, need to be considered. The part of the net internal capacity change attributed to capacity modifications can be determined by holding the EFORd level constant at the prior auction s level. The EFORd effect is the measure of the net internal capacity change attributable to EFORd changes and not capacity modifications. The EFORd effect was MW. As shown in Table 8, the net capacity increase was 7,829.4 MW, holding the sell offer EFORds constant at the 2011/2012 BRA level. If the highest sell offer EFORd participants could have chosen had been the one year EFORd values, the EFORd effect would have been a positive MW compared to the actual EFORd effect of MW, a difference of 1,106.0 MW. The Duquesne generating resources would have had a total UCAP of 3,282.9 MW compared to the actual 3,187.2 MW, a difference of 95.7 MW. If the one EFORd values had been used rather than the higher of the five year and the one year, the net internal capacity increase would have been 11,272.3 MW rather than the actual net internal capacity increase of 10,070.6 MW, a difference of 1,201.7 MW. Table 11 shows the auction results if the maximum EFORd which participants could submit had been the one year EFORd and if all eligible participants had submitted EFORd offer segments where the sell offer price was at net CONE and the MW value was equal to the ICAP times the positive difference between the five year EFORd and the one year EFORd. More UCAP MW would have been offered as a result of lower sell offer EFORds, and sell offer prices would have been higher for the EFORd offer segments. The binding constraints would have remained the same. PSEG North and DPL South clearing prices and quantities would have remained the same. EMAAC would have cleared at $ per MW day with a total EMAAC clearing quantity of 31,094.3 MW. MAAC would have cleared at $ per MW day with a total MAAC clearing quantity of 65,452.4 MW. The RTO would have cleared at $16.59 per MW day compared to the actual clearing price of $16.46 per MW day. The entire RTO clearing quantity would have remained the same at 136,143.5 MW. The conclusion is that the five year EFORd option together with the elimination of the EFORd offer segment did not have a significant impact on the market results. If the maximum EFORd which participants could submit was the one year EFORd and participants could not submit EFORd offer segments, the UCAP conversion would have been affected, resulting in more UCAP MW offered into the auction. PSEG North and DPL South clearing prices and quantities would have remained the same. EMAAC would not have constrained and would have cleared with MAAC. MAAC would have cleared at $ per MW day compared to $ per MW day. The RTO would have cleared at $14.84 per MW day compared to the actual clearing price $16.46 per MW day. Monitoring Analytics

19 (See Table 11) The conclusion is that the inclusion of the maximum of the five year or the one year EFORd had a relatively small impact on the market results. ILR and the Short Term Resource Procurement Target Effective for the 2012/2013 planning year, ILR was eliminated. It was replaced by the short term resource procurement target. Prior to this, PJM subtracted the ILR forecast from the reliability requirement. Under the current rules, 2.5 percent of the reliability requirement is removed from the demand curve. The rationale is to provide for short lead time resource procurement in incremental auctions for the given delivery year. For the 2012/2013 BRA, the 2.5 percent reduction resulted in the removal of 3,343.3 MW from the RTO demand curve. In the 2011/2012 BRA, removal of the ILR forecast from the reliability requirement resulted in a reduction in demand of 1,593.8 MW, or 1.2 percent of the reliability requirement of 130,658.7 MW. Table 12 shows the results if the reliability requirements had not been reduced by 2.5 percent short term resource procurement target and everything else had remained the same. The clearing price for DPL South would have been the same, but the clearing quantity would have increased to 1,305.5 MW. PSEG North would not have constrained, but clearing prices would have been the same as PSEG North would have cleared with EMAAC and the clearing quantity would have increased to 3,558.2 MW. The EMAAC clearing price would have increased to $ per MW day and the clearing quantity would have increased to 31,635.0 MW. The MAAC clearing price would have increased to $ per MW day and the clearing quantity would have increased to 66,394.0 MW. The RTO clearing price would have increased to $23.92 per MW day and the clearing quantity would have increased to 139,486.8 MW. The conclusion is that the removal of 2.5 percent of demand did not have a significant impact on DPL South or PSEG North but did have a significant impact on EMAAC and MAAC and on the RTO market. The removal of 2.5 percent of demand reduced the clearing prices and quantities for EMAAC, MAAC and the RTO. Table 19 shows the combined impact of not mitigating DR offers and not making the 2.5 percent demand adjustment. The conclusion is the same. The MMU recommends the careful reconsideration of the use of the 2.5 percent demand adjustment. The logic of reducing demand in a market design that looks three years forward, to permit other resources to clear in incremental auctions, is questionable. There are tradeoffs in using a one year forward or a three year forward design, but the design should be implemented on a consistent basis. Removing a portion of demand affects prices at the margin, which is where the critical signal to the market is determined. In the 2012/2013 BRA, the result was to reduce prices in the eastern part of PJM and to reduce the quantity of capacity purchased in the eastern part of PJM, although clearing prices in the two small constrained eastern LDAs were not affected. Monitoring Analytics

20 The result was also to significantly reduce the clearing price for the RTO market, affecting substantial MW of capacity. Impact of Increased ACR Default Rate Effective this auction, ACR default rates were increased. If offer caps had been calculated based on the old default ACR rates, all binding constraints would have remained the same. The LDA clearing prices and quantities would have remained the same. The RTO would have cleared at $12.20 per MW day compared to the actual clearing price of $16.46 per MW day, and the total RTO clearing quantity would have remained the same at 136,143.5 MW. Monitoring Analytics

21 Tables and Figures for RTO Section Table 6 RTO offer statistics: 2012/2013 RPM Base Residual Auction Percent of ICAP (MW) UCAP (MW) Available ICAP Total internal RTO capacity (gen, DR, and EE) 179, ,953.3 FRR (26,302.1) (24,264.8) Imports 4, ,831.6 RPM capacity 157, ,520.1 Percent of Available UCAP Exports (2,783.9) (2,637.1) FRR optional (1,684.2) (1,465.5) Excused (48.0) (44.2) Available 153, , % 100.0% Generation offered 142, , % 92.8% DR offered 9, , % 6.8% EE offered % 0.4% Total offered 153, , % 100.0% Unoffered % 0.0% Cleared in RTO 132, , % 87.0% Cleared in LDAs 10, , % 6.7% Total cleared 143, , % 93.7% Uncleared in RTO 6, , % 4.4% Uncleared in LDAs 3, , % 1.9% Total uncleared 9, , % 6.3% Reliability requirement 133,732.4 Total cleared 136,143.5 Short-Term Resource Procurement Target 3,343.3 Net excess/(deficit) 5,754.4 Resource clearing price ($ per MW-day) $16.46 A Preliminary zonal capacity price ($ per MW-day) $16.46 B Base zonal CTR credit rate ($ per MW-day) $0.00 C Preliminary net load price ($ per MW-day) $16.46 B-C Monitoring Analytics

22 Table 7 Capacity modifications (ICAP): 2012/2013 RPM Base Residual Auction 33 ICAP (MW) RTO MAAC EMAAC PSEG NORTH DPL SOUTH Generation increases 1, (1,003.0) Generation decreases (3,018.3) (1,906.2) (815.0) (34.8) Capacity modifications net increase/(decrease) (1,253.4) (1,210.6) (667.0) (767.7) (34.8) DR increases 9, ,586.6 (187.6) DR decreases (1,229.9) (876.9) 1, DR modifications increase/(decrease) 7, , , EE increases Net capacity/dr modifications increase/(decrease) 7, , (701.4) 27.7 Duquesne Gen 3,210.0 Duquesne DR Duquesne EE 0.2 Net Internal Capacity Increase/(Decrease) 10, , (701.4) 27.7 Table 8 Capacity modifications (UCAP): 2012/2013 Base Residual Auction UCAP (MW) RTO MAAC EMAAC PSEG NORTH DPL SOUTH Generation increases 1, Generation decreases (2,507.6) (1,500.7) (713.2) (551.3) (31.8) Capacity modifications net increase/(decrease) (851.8) (839.4) (385.2) (509.0) (31.8) DR increases 9, , , DR decreases (1,272.3) (907.1) (194.0) DR modifications increase/(decrease) 8, , , EE increases Net capacity/dr modifications increase/(decrease) 7, , ,120.1 (440.5) 32.8 EFORd effect (944.1) (502.1) (185.1) DR effect (1.9) (0.9) (0.5) Duquesne Gen 2,996.2 Duquesne DR Duquesne EE 0.2 Net Internal Capacity Increase/(Decrease) 10, , (422.2) Only cap mods and DR mods that had a start date on or before June 1, 2012 are included. Monitoring Analytics