{"document":{"slug":"complaint-el27-11-exelon","title":"Complaint Requesting Fast Track Processing of Exelon Corporation (prompt capacity auction from the 2030/31 Delivery Year)","issued":"2026-11-03","accession":"20261103-5191","docket":"EL27-11-000","group":"Exelon complaint seeking a prompt PJM capacity auction","filer":"Exelon","kind":"complaint (fast track)","file":"sources/originals/20261103-5191_Complaint of Exelon Corporation - 11.3.2026.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20261103-5191","sha256":"25acac84decf91df2aa5c3b823440f1949a78fb4dbac9dd718bc7db19f9b57a7","pages":61,"tokens":18031,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":126,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \nExelon Corporation, \n) \n \n \n) \n \nComplainant \n) \n \n \n) \n \nv. \n) \nDocket No. EL27-___-000 \n \n) \n \nPJM Interconnection, L.L.C., \n) \n \n \n) \n \nRespondent \n) \n \n \n) \n \n \nCOMPLAINT REQUESTING FAST TRACK PROCESSING OF  \nEXELON CORPORATION \n/s/ Jordan Kwok \n/s/ Thomas S. DeVita \nJordan Kwok \nThomas S. DeVita \nDirector, Federal Regulatory Affairs \nKimberly B. Frank \nExelon Corporation \nStuart B. Robbins \n701 Ninth Street, N.W. \nK&L Gates LLP \nWashington, D.C. 20068 \n1601 K Street, NW \n(667) 313-0421 \nWashington, DC  20006 \njordan.kwok@exeloncorp.com \n(202) 778-9000 \n \nthomas.devita@klgates.com \n/s/ Alejandro Bautista \nkimberly.frank@klgates.com \nAlejandro Bautista \nstuart.robbins@klgates.com \nAssistant General Counsel \n \nExelon Corporation \nCounsel for Exelon Corporation  \n2301 Market Street \n \nPhiladelphia, PA 19101 \n \n(267) 533-0120 \n \nalejandro.bautista@exeloncorp.com \n \n \n \n \nDated: November 3, 2026"},{"page":2,"startToken":126,"endToken":414,"text":"Table of Contents \n \n \n-i- \n \n \nI. \nINTRODUCTION .................................................................................................... 3 \nII. \nPARTIES AND COMMUNICATIONS................................................................. 10 \nA. \nComplainant Exelon.................................................................................... 10 \nB. \nRespondent PJM ......................................................................................... 11 \nC. \nCommunications ......................................................................................... 11 \nIII. \nBACKGROUND .................................................................................................... 12 \nIV. \nLEGAL ARGUMENT ............................................................................................ 14 \nA. \nThe Current Three-Year Forward Period of RPM is No Longer Just and \nReasonable. ................................................................................................. 14 \ni. \nThe risk balancing analysis the Commission relied on in 2006 to \naccept the load forecast inaccuracies inherent in RPM’s multi-year \nforward period has fundamentally collapsed in 2026. .................... 14 \na. \nEvidence that PJM Load Forecast Inaccuracies Have \nIncreased Since 2006. ......................................................... 16 \nb. \nEvidence that Capacity Resources cannot be constructed in \nthe PJM Region within the current three-year cycle. .......... 21 \nii. \nThe prospective assumptions in 2006 regarding the ability of RPM’s \nmulti-year forward period to incentivize LSE bilateral contracting \nand risk hedging have been disproven over the course of 20 years.\n......................................................................................................... 25 \niii. \nThe current three-year forward period inhibits efficient resource exit \nand Deactivation, as it requires generation owners to invest in the \nabsence of reasonable predictability in future operational capability \nand environmental policy. ............................................................... 30 \na. \nOperational Uncertainties ................................................... 32 \nb. \nEnvironmental Policy Uncertainties ................................... 33 \niv. \nPJM’s current capacity accreditation methodology (ELCC) bears no \nresemblance to the eFORd model considered by the Commission in \n2006, and the three-year forward period forces PJM to integrate \nspeculative assumptions into its ELCC modeling. ......................... 40 \nv. \nThe current three-year forward period undermines the accuracy of \nother BRA planning parameters, including the assumed resource mix \nin each Locational Deliverability Area used to calculate \nCETO/CETL values, leading to unjust and unreasonable results. .. 44 \nB. \nThe Commission Should Adopt a Prompt Auction Schedule as the Just and \nReasonable Replacement Rate. ................................................................... 46 \ni. \nA prompt auction will significantly improve the accuracy of key \nBRA auction parameters, resulting in capacity prices that better"},{"page":3,"startToken":414,"endToken":627,"text":"-ii- \n \n \nreflect actual supply and demand fundamentals and system \nconditions in the Delivery Year. ..................................................... 47 \nii. \nA prompt auction will significantly enhance the quality of \ninformation and the accuracy of the price signal used in generator \nDeactivation decisions. ................................................................... 49 \niii. \nA prompt auction schedule will significantly enhance the quality of \ndata used in PJM’s ELCC capacity accreditation, thereby better \naligning both price and payments with resource contributions to \nresource adequacy. .......................................................................... 51 \niv. \nA prompt auction will significantly reduce the risks to new resources \nseeking to enter the market by creating more certainty regarding their \nexpected availability for the Delivery Year. ................................... 53 \nV. \nREFUND EFFECTIVE DATE ............................................................................... 54 \nVI. \nRULE 206 REQUIREMENTS ............................................................................... 54 \nA. \nGood faith estimate of financial impact or harm (Rule 206(b)(4)) ............. 54 \nB. \nPractical, operational, or nonfinancial impacts (Rule 206(b)(5)) ............... 54 \nC. \nWhether the matters are pending in any other FERC proceeding or other \nforum (Rule 206(b)(6)) ............................................................................... 54 \nD. \nSpecific relief or remedy requested (Rule 206(b)(7)) ................................. 55 \nE. \nDocuments supporting the complaint (Rule 206(b)(8)) .............................. 55 \nF. \nUse of alternative dispute resolution (Rule 206(b)(9)) ............................... 55 \nG. \nNotice (Rule 206(b)(10)) ............................................................................ 55 \nH. \nRequest for Fast Track Processing (Rule 206(b)(11)) ................................ 55 \nVII. \nSERVICE AND NOTICE....................................................................................... 56 \nVIII. \nCONCLUSION ....................................................................................................... 56"},{"page":4,"startToken":627,"endToken":867,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \nExelon Corporation, \n) \n \n \n) \n \nComplainant \n) \n \n \n) \n \nv. \n) \nDocket No. EL27-___-000 \n \n) \n \nPJM Interconnection, L.L.C., \n) \n \n \n) \n \nRespondent \n) \n \n \n) \n \n \nCOMPLAINT REQUESTING FAST TRACK PROCESSING OF  \nEXELON CORPORATION  \nPursuant to sections 206, 306, and 309 of the Federal Power Act (“FPA”),1 and Rule \n206 of the Federal Energy Regulatory Commission’s (“FERC” or the “Commission”) Rules of \nPractice and Procedure,2 Exelon Corporation (“Exelon”) hereby submits this complaint against \nPJM Interconnection, L.L.C. (“PJM”).  For the reasons stated herein and in the attached \nAffidavits of Dr. Emma Nicholson and Deborah Sears,3 Exelon respectfully requests that the \nCommission: (i) find under FPA section 206 that the current three-year forward period of \nPJM’s Reliability Pricing Model4 (“RPM”) is no longer just and reasonable; and (ii) adopt as \n \n1 16 U.S.C. §§ 824e, 825e, 825h.   \n2 18 C.F.R. § 385.206.   \n3 The Nicholson Affidavit is included as Attachment A to this complaint, and the Sears Affidavit is included as \nAttachment B. \n4 Terms not otherwise defined herein shall have the same meaning as in the PJM Open Access Transmission \nTariff (“Tariff”), the Amended and Restated Operating Agreement of PJM Interconnection, L.L.C. (“Operating \nAgreement”), and the Reliability Assurance Agreement Among Load Serving Entities in the PJM Region \n(“RAA”).  The Tariff, Operating Agreement, and RAA are currently located under PJM’s “Intra-PJM Tariffs” \neTariff Title, available here: https://etariff.ferc.gov/TariffBrowser.aspx?tid=1731."},{"page":5,"startToken":867,"endToken":1258,"text":"2 \nthe just and reasonable replacement rate a “prompt” auction schedule, to run two months5 \nbefore a given Delivery Year, starting with the 2030/2031 Delivery Year and continuing \nbeyond.6   \nExelon respectfully requests that the Commission establish a refund effective date of \nJanuary 1, 2027, and permit Fast Track processing under Rule 206(h) to facilitate a \nCommission order by no later than January 31, 2027—currently the last day before the \nscheduled posting date of the planning parameters for the 2030/31 Delivery Year Base \nResidual Auction (“BRA”).  To be clear, nothing in this complaint is intended to apply to, or \notherwise disrupt the implementation of, the 2029/2030 Delivery Year BRA, which is \nscheduled to run in December 2026, nor any Reliability Backstop Procurement (“RBP”)7 \nauction.8   \nGranting the relief requested herein will have three important outcomes.  First, it will \nremedy an unjust and unreasonable aspect of RPM (the three-year forward period) by better \naligning the parameters used in each BRA with actual system conditions, resulting in an \nauction that relies on more accurate load forecasts, resource availability data, and capacity \naccreditation, and that facilitates more efficient resource entry and exit through improved \n \n5 As discussed herein, Exelon acknowledges that the Commission has wide legal discretion under FPA section \n206 in establishing the just and reasonable replacement rate, but recommends two months as a reasonable period \nbetween when PJM publishes its load forecast information in late January and the start of the Delivery Year on \nJune 1.  Two months also provides time for pre-auction activities to take place following the publication of the \nload forecast in January, gives Market Participants and PJM sufficient notice of the applicable auction parameters, \nand provides supply resources more than one month to make final operating arrangements if they clear the auction.   \n6 Exelon acknowledges that conforming changes to other PJM Governing Agreements may be needed, should the \nCommission grant the relief requested herein. \n7 See generally Docket Nos. ER26-3380-000, EL26-108-000. \n8 Out of an abundance of caution, Exelon is not proposing to apply the “prompt” auction remedy sought herein to \nthe 2029/2030 Delivery Year BRA, in light of the fact that the applicable planning parameters for the 2029/2030 \nDelivery Year BRA have already been posted.  See PJM Power Providers Group v. FERC, 96 F.4th 390 (3d Cir. \n2024)."},{"page":6,"startToken":1258,"endToken":1647,"text":"3 \nmarket signals.9  Second, it will functionally push out the date of the BRA for the 2030/31 \nDelivery Year, currently scheduled for May 2027, to approximately March 2030, thereby \npreventing Exelon’s customers, and PJM customers at large, from being exposed to the \nuncapped surge in capacity prices expected this coming spring under the current three-year \nforward RPM period while there is significant uncertainty about supply and demand \nfundamentals and PJM’s resource adequacy structure over this time horizon.  Third, it will \nprovide PJM and its stakeholder community, operating under the Commission’s oversight, \ncritical time to develop—and timely transition to—the comprehensive resource adequacy \nreforms that the Trump Administration, PJM Governors, and PJM itself recognize are critical \nto ensuring a long-term, enduring, and just and reasonable capacity construct in the PJM \nRegion.10 \nI. \nINTRODUCTION \nCustomers are, and always have been, at the center of Exelon’s core mission and values.   \nExelon is committed to addressing the mounting affordability pressures experienced every day \nby its more than 10.7 million customers in the PJM Region.11  In furtherance of this \n \n9 See Nicholson Affidavit, at ¶¶ 54-59. \n10 See, e.g., Statement of Principles Regarding PJM (Jan. 16, 2026) (hereafter, the “Statement of Principles”) \n(“PJM should immediately embark on a stakeholder process to reform the capacity market to ensure long-term \nviability and prevent consumers from bearing excessive ongoing costs, with the expectation that these reforms be \nimplemented in time for the BRA currently scheduled for May 2027.”); Powering Reliability Through Market \nDesign at 4 (May 6, 2026) (hereafter, the “PJM White Paper”) (“On Jan. 16, 2026, the PJM Board of Managers \ndirected PJM staff to undertake a holistic review of the capacity market design and investment incentives. The \nBoard recognized that the market’s current price volatility—while economically rational—is placing \nunsustainable stress on the governmental compact that allows the market to function, and that the foundational \nassumptions of the Reliability Pricing Model design must be reexamined in a resource-constrained world.  This \nwhite paper is PJM’s response to that directive.”).  The Statement of Principles is available here: \nhttps://www.energy.gov/documents/statement-principles-regarding-pjm.  The PJM White Paper is available here: \nhttps://www.pjm.com/-/media/DotCom/library/reports-notices/special-reports/2026/20260506-powering-\nreliability-through-market-design.pdf.  \n11 More information about the Exelon Promise is available here: https://www.exeloncorp.com/company/exelon-\npromise."},{"page":7,"startToken":1647,"endToken":1993,"text":"4 \ncommitment, Exelon submits this complaint against the RPM three-year forward period, to \nensure the people and businesses it serves, and the customers of the PJM Region more broadly, \nreceive what they are entitled to—market outcomes predicated on accurate information. \nThe auction schedule of RPM that has successfully driven efficient outcomes for \nExelon customers in the past has proven incapable of meeting the needs of the PJM Region \ntoday and into the future.  Customers in all six Exelon service territories are directly impacted \nby the extraordinary prices produced by RPM in recent years, beginning with the 2025/2026 \nDelivery Year BRA that cleared at several multiples of the historical average capacity price in \nPJM, and at roughly ten times the prior year’s clearing price.12  The crisis has only deepened \nsince then, with the 2027/2028 and 2028/2029 Delivery Year BRAs clearing at the temporary \nCommission-approved price cap and simultaneously falling thousands of MWs short of PJM’s \ntarget Installed Reserve Margin.13  While PJM’s staff, management, and Board of Managers \n(“Board”) have diligently and competently administered RPM Auctions over the last two \ndecades, it is self-evident that RPM in its current structure is fundamentally broken.  Not only \nare PJM customers at large being forced to pay unprecedented prices for capacity, they are not \ngetting sufficient capacity in return, and are paying for a widening gap between supply and \ndemand as a reliability deficit looms.   \nAs the Commission correctly observed on September 30, 2026, “[w]e think it clear that \nPJM’s ordinary instrument for procuring sufficient capacity to meet PJM’s reliability \nrequirement, the RPM, has failed to keep pace with the unprecedented influx of large load into \n \n12 See, e.g., PJM Capacity Prices Spike 10-Fold in 2025/2026 Auction, RTO Insider, Devin Leith-Yessian (Jul. \n30, 2024),  https://www.rtoinsider.com/84356-pjm-capacity-prices-spike-2025-26-auction/.   \n13 PJM’s 2027/2028 BRA report is available here: https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-\nauction-info/2027-2028/2027-2028-bra-report.pdf.  PJM’s 2028/2029 BRA report is available here: \nhttps://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/2028-2029/2028-2029-bra-results-\nreport.pdf."},{"page":8,"startToken":1993,"endToken":2319,"text":"5 \nthe PJM Region in recent years.”14  Exelon agrees with the Commission’s assessment and is \ntaking action.  In this complaint, Exelon demonstrates that an integral component of RPM—\nthe three-year forward period—is no longer just and reasonable, because it produces market \noutcomes that charge customers on the basis of parameters estimated four years in advance of \ndelivery completion, thereby structuralizing uncertainty and inaccuracy with no proportional \nbenefit.  While Exelon, like other PJM Transmission Owners and PJM itself, has taken steps \nto proactively enhance the accuracy of its own load forecast and to eliminate speculative \ndemand (including through its pioneering use of Transmission Security Agreements \n(“TSAs”)),15 it is still fundamentally bound by RPM’s mandate to predict reality years in \nadvance—a challenge exacerbated by the distinct nature, characteristics, and volatile \ndevelopment schedules of today’s large loads, as well as the changing nature of market \ndynamics and federal, state, and local environmental, permitting, and tax policies.    \nThe market outcomes produced under this paradigm create an unjustifiable chasm \nbetween the costs customers pay and the capacity they receive, while simultaneously failing to \naccurately portray the underlying supply and demand dynamics of the PJM Region in a manner \nthat inhibits efficient resource exit, and fails to incentivize efficient resource entry.  \nAccordingly, Exelon respectfully requests the Commission exercise its authority under FPA \nsection 206 to find the existing three-year forward period of RPM unjust and unreasonable, \nand direct PJM to establish a just and reasonable “prompt” auction schedule, to run two months \nbefore a given Delivery Year, starting with the 2030/2031 Delivery Year and continuing \n \n14 PJM Interconnection, L.L.C., 196 FERC ¶ 61,245, at P 29 (2026). \n15 A TSA is a customer protection mechanism that requires large new power users like data centers to make firm \nfinancial commitments for the transmission service that the grid must be ready to provide.  More information \nabout TSAs is available here: https://www.exeloncorp.com/grid/exelons-transmission-security-agreements-a-\npioneering-model-for-customer-protection1"},{"page":9,"startToken":2319,"endToken":2646,"text":"6 \nbeyond.  Exelon acknowledges that the Commission has wide legal discretion under FPA \nsection 206 in establishing the just and reasonable replacement rate,16 but recommends two \nmonths as a reasonable period between when PJM publishes its load forecast information in \nlate January and the start of the Delivery Year on June 1.  Two months also provides time for \npre-auction activities to take place following the publication of the load forecast in January, \ngives Market Participants and PJM sufficient notice of the applicable auction parameters, and \nprovides Capacity Resource owners more than one month to make final operating \narrangements if they clear the auction.   \nWhile this particular complaint is narrowly focused on the three-year forward period \nof RPM, and the prompt auction remedy proposed herein is just and reasonable on its own, \nExelon acknowledges the targeted surgery requested in this complaint will not heal all that ails \nRPM.  Developments in recent years have exposed broad structural shortcomings inherent in \nthe PJM resource adequacy paradigm and capacity market framework that have led to the crisis \nthe PJM Region faces today.  These include (i) the explosive growth of data center load, (ii) a \nhistoric procurement crisis for components essential to the development of new capacity, (iii) \nchallenges in the permitting and financing of new generation, (iv) frequent market rule \nchanges, and (v) reactive interventions aimed at promoting just, reasonable, and affordable \nrates for customers.  There is accordingly a considerable amount of work still to be completed \nby PJM and its stakeholder community to identify a more durable resource adequacy construct \nthat can reliably support the efficient entry and exit of Capacity Resources from the PJM \n \n16 See, e.g., Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153, 159 (D.C. Cir. 1967) (“[T]he breadth of agency \ndiscretion is, if anything, at zenith when the action assailed relates primarily . . . to the fashioning of policies, \nremedies and sanctions . . . in order to arrive at maximum effectuation of Congressional objectives.”)."},{"page":10,"startToken":2646,"endToken":3169,"text":"7 \nRegion, while simultaneously protecting consumers from the extreme price and reliability \noutcomes that have become the unjust and unreasonable norm. \nIn the interim, through this complaint, Exelon is providing the Commission with a legal \npathway and evidentiary record to immediately address one significant defect of RPM (the \nthree-year forward period), and in doing so ensure both customers and suppliers in the PJM \nRegion benefit from an auction schedule that better reflects actual supply and demand \nfundamentals, and sends more accurate investment signals.  Such action directly aligns with \nthe Commission’s core responsibilities under the FPA, as the Commission’s “first and foremost \nduty” under the statute is “to protect consumers from unjust and unreasonable rates,”17 and the \nCommission has long viewed efficient, accurate, and competitive markets as a vehicle to \nachieve that end.18  As an ancillary but not insignificant benefit, granting the instant complaint \nwould provide much-needed time for PJM, States, and the PJM stakeholder community to \nthoughtfully develop comprehensive and durable reforms to the capacity construct in the PJM \nRegion and submit a proposal to the Commission, without the unnecessary specter of extreme \n \n17 Morgan Stanley Cap. Grp. Inc. v. Pub. Util. Dist. No. 1 of Snohomish Cnty., 554 U.S. 527, 551 (2008) \n(quotations and citations omitted). See also Atl. Refin. Co. v. Pub. Serv. Comm’n of N.Y., 360 U.S. 378, 388 (1959) \n(The FPA’s sister, the Natural Gas Act, was “framed as to afford consumers a complete, permanent and effective \nbond of protection from excessive rates and charges.”); NAACP v. FPC, 520 F.2d 432, 438 (D.C. Cir. 1975) (“The \nCommission’s primary task . . . is to guard the consumer from exploitation . . . .”), aff’d, 425 U.S. 662 (1976).   \n18 See Fed. Energy Regulatory Comm’n v. Elec. Power Supply Ass’n, 577 U.S. 260, 267-68 (2016) [hereinafter \nFERC v. EPSA] (“The Commission instead undertakes to ensure ‘just and reasonable’ wholesale rates by \nenhancing competition—attempting, as we recently explained, ‘to break down regulatory and economic barriers \nthat hinder a free market in wholesale electricity.’”) (citing Morgan Stanley Capital Group Inc. v. Public Util. \nDist. No. 1 of Snohomish Cty., 554 U.S. 527, 536 (2008)); Public Citizen, Inc. v. FERC, 7 F.4th 1177, 1194 (D.C. \nCir. 2021) (explaining that “the whole premise of the Commission’s market-based system is that a properly \ncompetitive market will necessarily produce just and reasonable prices,” and that the Commission satisfies its \nstatutory obligations by ensuring that markets are fair, competitive, and unmanipulated); Calpine Corp. et. al., \n171 FERC ¶ 61035, at P 139 (2020) (upholding determination on rehearing that the relevant replacement rate will \nenable PJM’s capacity market to send price signals on which both investors and consumers can rely to guide the \nentry and exit of economically-efficient capacity resources, will support the capacity market’s ability to attract \ninvestments, and “supports the capacity market’s core objective of maintaining resource adequacy at just and \nreasonable rates, particularly during periods when entry is needed.”); Wholesale Competition in Regions with \nOrganized Electric Markets , Order No. 719, 125 FERC ¶ 61,071, at P 13 (tying reforms to wholesale competition \nto its responsibilities under FPA §§ 205 and 206)."},{"page":11,"startToken":3169,"endToken":3531,"text":"8 \npricing outcomes with each passing BRA.  Additionally, remedying this defect by moving to \na prompt auction schedule now, while this broader market redesign takes place, will have \nseveral immediate benefits for the PJM Region: \n• It will allow the PJM Region to transition more quickly to the new resource \nadequacy structure once such a construct is ultimately established.  Maintaining the \nthree-year forward period would push the completion of any transition ahead to, at \nbest, four years (the current forward period plus the Delivery Year) after those \nreforms are accepted.  In the current fast-moving energy environment, that is simply \ntoo long, and customers should not be expected to keep taking on long-term \ncommitments to this current broken model. \n• Similarly, it will allow future market reforms to “sink in” more quickly should \nfuture adjustments be needed.  If history is any guide, there will likely be a need, \neven after this round of reforms, to adjust rules to address lingering shortcomings.  \nA prompt structure allows PJM customers to benefit from future market \nimprovements more quickly than the existing three-year forward period.  \n• It will relieve the challenges and administrative burden on PJM and stakeholders \nassociated with constantly running and participating in Incremental Auctions \n(“IAs”). \n• It will improve alignment of participation timing for non-conventional resources \nlike demand response, which are challenged by long forward commitments in the \ncontext of capacity obligations, and eliminate concerns regarding speculative price \narbitrage. \nCritically, the discrete remedy sought by Exelon through this complaint is not new.  \nThe Commission already found prompt auction schedules to be just and reasonable in ISO-NE \nInc. (“ISO-NE”),19 the New York Independent System Operator, Inc. (“NYISO”),20 and the \nMidcontinent Independent System Operator, Inc. (“MISO”),21 even though these three regions \nhave diverse approaches to resource adequacy, ranging from utility-owned generation under \n \n19 See ISO New England Inc., 194 FERC ¶ 61,249 (2026) (“ISO-NE Order”).  \n20 See New York Independent System Operator, Inc., Market Administration and Control Area Services Tariff, \n§§ 5.13, 5.14.1.1. \n21 See Midcontinent Indep. Sys. Operator, Inc., 162 FERC ¶ 61,176, at PP 70, 74 (2018) (“MISO Order”), reh’g \ndenied, 170 FERC ¶ 61,215, at PP 125-26 (2020) (“MISO Rehearing Order”)."},{"page":12,"startToken":3531,"endToken":3854,"text":"9 \nstate commission Integrated Resource Plans (“IRP”) to fully restructured, market-based \nframeworks.  Action by the Commission in this proceeding will align PJM’s capacity auction \nschedule with all other Regional Transmission Organizations and Independent System \nOperators (“RTOs/ISOs”) that have centralized capacity market constructs.   \nExelon presents its legal case under FPA section 206 in Part IV of this complaint, which \nis divided into two subparts.  In Part IV.A, Exelon demonstrates that the three-year forward \nperiod of RPM has become unjust, unreasonable, unduly discriminatory or preferential under \nFPA section 206, for the following five reasons: \n1. The risk balancing analysis the Commission relied on in 2006 to accept the load \nforecast inaccuracies inherent in RPM’s multi-year forward period has \nfundamentally collapsed in 2026.   \n2. The prospective assumptions in 2006 regarding the ability of RPM’s multi-year \nforward period to incentivize Load-Serving Entity (“LSE”) bilateral contracting \nand risk hedging have been disproven over the course of 20 years. \n3. The current three-year forward period inhibits efficient resource exit and \nDeactivation, as it requires generator owners to invest in the absence of reasonable \npredictability in future operational capability and environmental policy.   \n4. PJM’s current capacity accreditation methodology, Effective Load Carrying \nCapability (“ELCC”) bears no resemblance to the Equivalent Forced Outage Rate \n- demand (“eFORd”) model considered by the Commission in 2006, and the three-\nyear forward period forces PJM to integrate speculative assumptions into its ELCC \nmodeling. \n5. The current three-year forward period undermines the accuracy of other BRA \nplanning parameters, including the assumed resource mix in each Locational \nDeliverability Area (“LDA”) used to calculate Capacity Emergency Transfer \nObjective (“CETO”) and Capacity Emergency Transfer Limit (“CETL”) values, \nleading to unjust and unreasonable results.  \nIn Part IV.B, Exelon requests that the Commission replace the three-year forward \nperiod of RPM with a prompt auction, starting with the 2030/2031 Delivery Year and \ncontinuing beyond.  Exelon explains that a prompt auction is just and reasonable for the \nfollowing four reasons:"},{"page":13,"startToken":3854,"endToken":4108,"text":"10 \n1. A prompt auction will significantly improve the accuracy of key BRA auction \nparameters, resulting in capacity prices that better reflect actual supply and demand \nfundamentals and system conditions in the Delivery Year. \n2. A prompt auction will significantly enhance the quality of information and the \naccuracy of the price signal used in generator Deactivation decisions.  \n3. A prompt auction will significantly enhance the quality of data used in PJM’s \nELCC capacity accreditation, thereby better aligning both price and payments with \nresource contributions to resource adequacy. \n4. A prompt auction will significantly reduce the risks to new resources seeking to \nenter the market by creating more certainty regarding their expected availability for \nthe Delivery Year. \nII. \nPARTIES AND COMMUNICATIONS \nA. \nComplainant Exelon \nExelon is one of the nation’s largest utility holding companies, providing transmission \nand distribution service to nearly 11 million customers in the PJM Region through its regulated \nsubsidiaries Atlantic City Electric Company (“ACE”), Baltimore Gas and Electric Company \n(“BGE”), Commonwealth Edison Company (“ComEd”), Delmarva Power & Light Company \n(“DPL”), PECO Energy Company (“PECO”), and Potomac Electric Power Company \n(“Pepco”) (together, the “Exelon Companies”).  Exelon’s more than 20,000 employees \ndedicate their time and expertise to supporting the communities they live in and serve through \nreliable, affordable, and efficient energy delivery, workforce development, economic \ndevelopment, and volunteerism.  \nThe Exelon Companies are public utilities under the FPA, and signatories to both the \nPJM Consolidated Transmission Owners Agreement (“CTOA”) in their capacity as PJM \nTransmission Owners, and the RAA in their capacity as PJM LSEs."},{"page":14,"startToken":4108,"endToken":4374,"text":"11 \nB. \nRespondent PJM \nPJM is the nation’s largest RTO, coordinating the movement of wholesale electricity \nin all or parts of 13 states and the District of Columbia.22  As an RTO, PJM is responsible for \nthe reliability of the high-voltage transmission system serving 68 million people in all or parts \nof Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, \nOhio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.  PJM \nalso administers the PJM wholesale electricity markets, including the Day-ahead Energy \nMarket, the Real-time Energy Market, ancillary services markets, and, as relevant here, the \nRPM. \nC. \nCommunications  \nAll correspondence and communications to Exelon in this docket should be addressed \nto the following individuals, whose names should be entered on the official service list \nmaintained by the Secretary in connection with these proceedings:23 \nJordan Kwok \nThomas S. DeVita \nDirector, Federal Regulatory Affairs \nKimberly B. Frank \nExelon Corporation \nStuart B. Robbins \n701 Ninth Street, N.W. \nK&L Gates LLP \nWashington, D.C. 20068 \n1601 K Street, NW \n(667) 313-0421 \nWashington, DC  20006 \njordan.kwok@exeloncorp.com \n(202) 778-9000 \n \nthomas.devita@klgates.com \nAlejandro Bautista \nkimberly.frank@klgates.com \nAssistant General Counsel \nstuart.robbins@klgates.com \nExelon Corporation \n \n2301 Market Street \nCounsel for Exelon Corporation  \nPhiladelphia, PA 19101 \n \n(267) 533-0120 \n \nalejandro.bautista@exeloncorp.com \n \n \n \n22 See PJM Interconnection, About PJM (last visited Sept. 27, 2026), https://www.pjm.com/about-pjm.  \n23 Exelon respectfully requests a waiver of Rule 203(b)(3), 18 C.F.R. § 385.203(b)(3), to allow the inclusion of \nmore than two persons on the official service list."},{"page":15,"startToken":4374,"endToken":4671,"text":"12 \nIII. \nBACKGROUND \nThe concept of a multi-year forward period for RPM first emerged in PJM’s August \n2005 Initial RPM Proposal,24 and was designed to address one of several core deficiencies with \nPJM’s then-existing capacity construct—namely that, as PJM explained, the construct did “not \nlook far enough into the future to secure capacity in time to meet reliability needs.”25  In 2005, \nthis defect was glaring.  At the time, PJM’s capacity construct only required that Capacity \nResources be committed for one day, and there was little incentive to commit for longer \nperiods.  Moreover, Capacity Resources were permitted to “opt out” of their Capacity Resource \nstatus with as little as 36 hours’ notice.  PJM administered capacity credit markets only twelve \nmonths at a time, which were designed to accommodate short-term competitive load-switching \nunder retail choice, and were incapable of sustaining long-term generation investment.  As \nPJM described it, “[s]imply put, the short-term nature of the current PJM capacity construct is \nfundamentally inconsistent with the need to preserve system reliability in the longer term.”26  \nTo remedy these shortcomings, PJM proposed a four-year forward period for RPM.   \nOn April 20, 2006, the Commission issued its Initial RPM Order, finding that PJM’s \nexisting capacity construct was unjust and unreasonable and establishing additional procedures \nto resolve several remaining issues regarding the just and reasonable replacement rate.27  As \nrelevant here, the Commission accepted the four-year forward period of RPM, finding that \n \n24 PJM Interconnection, L.L.C., PJM Section 205 and 206 Filing of PJM Interconnection, L.L.C., Docket Nos. \nER05-1410-000 and EL05-148-000 (Aug. 31, 2005) (“August 2005 Initial RPM Proposal”).  \n25 Id., at 5. \n26 Id., at 9. \n27 PJM Interconnection, L.L.C., 115 FERC ¶ 61,079, at P 1 (2006) (“April 2006 Initial RPM Order”)."},{"page":16,"startToken":4671,"endToken":4956,"text":"13 \n“four years is a reasonable period in which solutions can be placed in operation in response to \nthe RPM’s base residual auction.”28 \nOn September 29, 2006, PJM submitted the RPM Settlement, which proposed to \nresolve all outstanding issues in the proceeding regarding RPM.29  Among other things, the \nRPM Settlement retained a multi-year forward period accepted by the Commission in the April \n2006 Initial RPM Order, but shortened the period between the BRA and the start of the \nDelivery Year from four to three years.  As explained in the RPM Settlement, the parties \ndetermined three years was sufficient to meet the essential purpose of a forward commitment, \nnamely to provide a credible prospect for new entry via the construction of new resources.30  \nTo this point, the settlement noted that PJM previously presented witness testimony indicating \na typical 33-month period between signing of an Incremental Facilities Study Agreement for a \nnew plant and the plant’s commercial operation date.31 \nOn December 22, 2006,32 the Commission approved the RPM Settlement, subject to \ncertain conditions, including the proposed three-year-forward period of RPM.  Over the last \ntwenty years, many of the RPM market design components from the original RPM Settlement \nhave evolved and been improved upon, including capacity accreditation, performance \nobligations, and interface with PJM’s planning and operations regime.  Notably, however, with \n \n28 Id., at P 72. \n29 PJM Interconnection, L.L.C., Settlement Agreement and Explanatory Statement of the Settling Parties \nResolving All Issues, Docket Nos. ER05-1410-000 and -001, EL05-148-000 and -001 (Sept. 29, 2006) (“RPM \nSettlement”).  \n30 See RPM Settlement, at 11-12.  \n31 Id.  \n32 See PJM Interconnection, L.L.C., 117 FERC ¶ 61,331, at P 28 (2006) (“December Order Approving \nSettlement”)."},{"page":17,"startToken":4956,"endToken":5228,"text":"14 \nthe exception of the BRA delays starting in 2019, the three-year forward period auction \nschedule has remained unchanged since 2006. \nIV. \nLEGAL ARGUMENT \nA. \nThe Current Three-Year Forward Period of RPM is No Longer Just and \nReasonable.  \ni. \nThe risk balancing analysis the Commission relied on in 2006 to accept \nthe load forecast inaccuracies inherent in RPM’s multi-year forward \nperiod has fundamentally collapsed in 2026.   \nAs described above, the concept of a multi-year forward period was integral to PJM’s \noriginal RPM filing in 2005.  In the August 2005 Initial RPM Proposal, PJM predicated RPM \non a four-year forward period (later revised down to three years via the RPM Settlement), \nwhich aligned with what was at the time the expected development schedule for a new \ncombustion turbine (an estimated 33 months, as discussed above), according to PJM’s affiant \nMr. Pasteris.33  From the outset, PJM acknowledged that RPM’s proposed multi-year forward \nperiod, by definition, contained an inherent risk of load forecast inaccuracies.  PJM explained \nthat “the choice of the forward period represents a balance among many factors, including the \nrisk of estimation error . . . and the ease of participation by resources with relatively long lead \ntimes.”34  In applying this “balancing” of factors, PJM reasoned that “what is crucial is a market \nthat is sufficiently forward to provide the opportunity for additional competition and a greater \ndegree of forward price certainty, while not being so long that the estimation errors create a \nsubstantial risk of too much construction should the expected load fail[] to materialize.”35  \n \n33 See August 2005 Initial RPM Proposal, at 75-76. \n34 Id., at 77-78. \n35 Id., at 78."},{"page":18,"startToken":5228,"endToken":5578,"text":"15 \nIn its April 2006 Initial RPM Order approving RPM’s multi-year forward period, the \nCommission recognized what several protesters argued in the record—namely that “RPM may \nexpose customers to greater risks than they now face,” including “the inherent risk that a four-\nyear-forward estimate of how much capacity will be needed five years later will prove to be \nunreliable.”36  The Commission acknowledged these concerns were valid, but engaged in a \nrisk balancing analysis to justify acceptance of the risk of inaccuracy inherent in RPM’s multi-\nyear forward period.   \nWe agree, in part, with Morgan Stanley that RPM may cause \ncustomers to bear risks such as the risk that a four-year forward \nestimate of needed capacity may turn out to be inaccurate.  \nHowever, we think that the risk is reasonable when it is \ncompared to the risks of the current construct, namely that \nsufficient capacity resources may not be constructed to ensure \nthe preservation of reliability.37 \nTwenty years later, this risk-balancing analysis the Commission relied on in 2006 has \nfundamentally collapsed, and the resulting RPM framework that was explicitly predicated on \nit has become unjust and unreasonable.  As demonstrated below, not only have the load forecast \ninaccuracies inherent in RPM’s three-year forward period increased since 2006, but Capacity \nResources—and in particular the RPM Reference Resource38—are now functionally incapable \nof being constructed in the PJM Region within the current three-year cycle, leaving only the \ndownside pricing risk of those load forecast inaccuracies to be borne by customers.  Put another \nway, the very outcome the Commission sought to avoid in accepting the load forecast \n \n36 April 2006 Initial RPM Order, at P 66.  It is worth noting that the three-year forward period of RPM is \nfunctionally a “three year + one year” estimate and commitment by customers. \n37 Id., at P 71 (emphasis added). \n38 See Tariff, Definitions R-S (“Reference Resource” shall mean a combustion turbine generating station, \nconfigured with a single General Electric Frame 7HA turbine with evaporative cooling, Selective Catalytic \nReduction technology all CONE Areas, dual fuel capability, and a heat rate of 9.134 Mmbtu/ MWh.”)."},{"page":19,"startToken":5578,"endToken":5869,"text":"16 \ninaccuracies inherent in RPM’s multi-year forward period—“that sufficient capacity resources \nmay not be constructed to ensure the preservation of reliability”—is today the lived reality of \nthe PJM Region.  This conclusion is supported by several key pieces of evidence, which are \ndescribed below in subsections IV.A.i.a and IV.A.i.b.   \na. \nEvidence that PJM Load Forecast Inaccuracies Have Increased \nSince 2006. \nAs noted above, Exelon has taken concrete steps to improve the accuracy of its load \nforecast and eliminate speculative demand, including through its pioneering use of TSAs, \nwhich require firm financial commitments from large load customers.39  Notwithstanding these \nefforts, Exelon, the other Transmission Owners of the PJM Region, and PJM itself are \nnonetheless bound by RPM’s requirement to predict reality years into the future—a task made \nmore difficult by the nature, characteristics, and volatile development schedules of today’s \nlarge loads.  Beyond this, a forward period of this magnitude will, by definition, fail to capture \nchanges in business economics, federal and state environmental and regulatory policy, and \nlocal siting and permitting regulations, all of which play a vital role in the market outcomes of \nRPM. \nIrrespective of the efforts of Exelon, the PJM Transmission Owners, and PJM to \nenhance the accuracy of their load forecasts, RPM’s mandate to predict reality so far into the \nfuture creates uncertainty in PJM’s near-term load forecast that is persistent, consistent in \ndirection, and has increased in magnitude since 2006 when the Commission initially accepted \nRPM’s three-year forward period.  There are multiple data sets that support this conclusion.  \nFirst, Figure 2 of the Nicholson Affidavit illustrates the change in the peak load forecast \n \n39 More information about TSAs is available here: https://www.exeloncorp.com/grid/exelons-transmission-\nsecurity-agreements-a-pioneering-model-for-customer-protection1."},{"page":20,"startToken":5869,"endToken":6120,"text":"17 \nbetween the BRA, which has historically been held thirty-eight (38) months prior to the start \nof the Delivery Year, and the third IA, which is held approximately four months before the \nstart of the Delivery Year.  The magnitude of the load forecast inaccuracies (blue bars) between \nthe 2016/2017 BRA and the 2022/2023 BRA is significant, reveals a clear trend toward \noverestimation of load, and notably the need for forecast adjustments decreased in instances \nwhere the BRA forward period was shortened as a result of auction delays.  As Dr. Nicholson \nexplains, the increase in BRA load forecast precision shown in  Figure 2 of the Nicholson \nAffidavit is positively correlated with the shorter forecast horizon, as the 2023/24 through \n2026/27 BRAs had a shorter forward period due to auction delays.40  \nNicholson Affidavit - Figure 2  \nBRA Forward Period (Green, Right Axis) and Load Forecast \nChange between BRA and Third IA (Blue, Left Axis) \n \n \nSecond, the increase in magnitude in recent years of PJM load forecast inaccuracies \ncan also be observed in the growing size (in MW) of the Load Adjustments PJM makes to its \n \n40 Nicholson Affidavit, at ¶¶ 15-16. \n38\n38\n38\n35\n38\n38\n38\n13 12\n18\n11\n0\n5\n10\n15\n20\n25\n30\n35\n40\n-9%\n-7%\n-5%\n-3%\n-1%\n1%\n3%\n2016/17\n2017/18\n2018/19\n2019/20\n2020/21\n2021/22\n2022/23\n2023/24\n2024/25\n2025/26\n2026/27\nBRA  forward period, in months\n%  change, BRA   v. 3rd  IA"},{"page":21,"startToken":6120,"endToken":6586,"text":"18 \nload forecast model, which Dr. Nicholson describes in Table 2 of her Affidavit.  Where such \nadjustments historically represented no more than 2% of the projected summer peak load four \nto five years out as recently as the 2017 through 2021 forecasts, PJM’s 2026 forecast reflects \nadjustments of 18.4% and 21.7% of the summer peak for those same time horizons.41  Indeed, \nprojected year-over-year growth in summer peak tells the same story, rising from well under \n1% annually as recently as 2022 to a range of 3.1% to 4.4% in PJM’s 2025 load forecast and \n2.6% to 6.7% in the 2026 forecast.42  This trend in year-over-year growth is illustrated in Table \n3 of the Nicholson Affidavit. \nNicholson Affidavit - Table 2  \nLoad Adjustments as a Percent of the Summer Peak Load Forecasts, 2017 - 2026  \nHistorical PJM Load Forecasts by Year \n  \n2017 \n2018 \n2019 \n2020 \n2021 \n2022 \n2023 \n2024 \n2025 \n2026 \nY0 \n0.6% \n0.8% \n1.1% \n0.0% \n-0.2% \n0.6% \n1.9% \n1.8% \n2.3% \n4.1% \nY0 +1 \n0.7% \n1.0% \n1.3% \n0.1% \n-0.1% \n1.1% \n2.2% \n3.0% \n5.3% \n6.7% \nY0 +2 \n0.8% \n1.2% \n1.5% \n0.3% \n-0.1% \n1.6% \n2.4% \n4.8% \n8.3% \n9.8% \nY0 +3 \n1.0% \n1.4% \n1.6% \n0.4% \n0.0% \n2.0% \n2.5% \n6.3% \n11.4% \n13.0% \nY0 +4 \n1.2% \n1.6% \n1.8% \n0.5% \n0.1% \n2.6% \n2.6% \n7.8% \n14.4% \n18.4% \nY0 +5 \n1.4% \n1.7% \n1.9% \n0.4% \n0.0% \n2.7% \n2.7% \n8.9% \n17.8% \n21.7% \n \nNicholson Affidavit - Table 3  \nYear-Over-Year Growth in Summer Peak Load Forecasts, 2017 - 2026  \nHistorical PJM Load Forecasts by Year \n  \n2017 \n2018 \n2019 \n2020 \n2021 \n2022 \n2023 \n2024 \n2025 \n2026 \nY0+1 \n0.6% \n0.2% \n-0.3% \n1.0% \n0.5% \n0.3% \n0.5% \n1.5% \n3.1% \n2.6% \nY0+2 \n0.2% \n-0.3% \n0.4% \n1.0% \n0.6% \n0.6% \n0.8% \n2.2% \n3.3% \n3.2% \nY0+3 \n-0.4% \n0.3% \n0.5% \n0.6% \n0.4% \n0.6% \n1.2% \n1.9% \n3.5% \n3.6% \nY0+4 \n-0.2% \n0.3% \n0.4% \n0.4% \n0.3% \n0.7% \n1.0% \n1.9% \n3.6% \n6.7% \nY0+5 \n0.0% \n0.5% \n0.4% \n0.6% \n0.2% \n0.0% \n0.9% \n1.7% \n4.4% \n4.4% \n \nAs Dr. Nicholson notes, this is not a modeling failure; it reflects a structural shift in \nforecast uncertainty driven almost entirely by the nature and size of data center load growth in \n \n41 Id., at ¶¶ 20-21. \n42 Id., at ¶ 22."},{"page":22,"startToken":6586,"endToken":6947,"text":"19 \nthe PJM Region.  Not only is such uncertainty larger in magnitude given the size of the \nunderlying customers, but the forecasting challenges are also amplified by recent and ongoing \nsiting, permitting, and supply chain challenges nationwide, as well as the fast-changing \nbusiness environment and evolving regulatory constructs with which data center developers \nneed to contend with.43  These load forecast inaccuracies have real impacts on market \noutcomes.  As Dr. Nicholson explains, the three-year RPM forward period and assumptions \nabout large load growth, principally from data centers, are likely to overstate the peak load \nforecast that PJM uses to determine the Reliability Requirement and the amount of capacity \nthat PJM must procure in the BRA.44  This can lead to unjust and unreasonable outcomes.  \nProcuring too much capacity in the BRA unnecessarily increases costs for PJM Market \nParticipants, because if a portion of the large loads included in the load forecast used in the \nBRA do not materialize, capacity costs will increase for all customers.  This outcome is also \neconomically inefficient, because when it occurs the PJM Region purchases more capacity \nthan is necessary to ensure target levels of resource adequacy.   \nDr. Nicholson provides an illustrative example to demonstrate just how much load \nforecast inaccuracies can impact market prices, even in small percentages.  Figure 3 of the \nNicholson Affidavit is based on a VRR Curve constructed using PJM’s 2029/30 BRA \nparameters, the VRR Curve formulation the Commission accepted in Docket No. ER26-455, \nand no price collar.  As Dr. Nicholson explains, the blue plot shows an estimate of what the \nVRR Curve would be with the Reliability Requirement for the 2029/30 BRA, and the orange \n \n43 Id., at ¶¶ 14, 21-23, 27. \n44 Id., at ¶ 14.  Note that the PJM Region Reliability Requirement is defined as the Forecast Pool Requirement \nmultiplied by the Preliminary PJM Region Peak Load Forecast, less the sum of all Preliminary Unforced Capacity \nObligations of FRR Entities in the PJM Region; and, for purposes of the Incremental Auctions, the Forecast Pool \nRequirement multiplied by the updated PJM Region Peak Load Forecast, less the sum of all updated Unforced \nCapacity Obligations of FRR Entities in the PJM Region.”"},{"page":23,"startToken":6947,"endToken":7146,"text":"20 \nand green plots show what the VRR Curve would have been if the Reliability Requirement \nwere 1% or 2% lower, respectively.45  Both 1% and 2% are reasonable load forecast \nsensitivities to explore because they are consistent with historically observed forecast errors \nwithin a three-year forecast horizon in the 2016/17 through 2022/23 BRAs (see Figure 3 of the \nNicholson Affidavit), which occurred before the uncertainty inherent in large load growth seen \ntoday.  Additionally, when comparing the PJM load forecasts published in January 2025 and \nJanuary 2026, the Summer Peak forecasts for 2027 through 2029 fell by between 2.3% and \n2.6%.46  \nNicholson Affidavit - Figure 3 \nIllustrative Example of Cost Implications of the Reliability Requirement on the BRA \nClearing Price \n \n \n \n45 Id., at ¶ 29. \n46 Id. \n$0\n$50\n$100\n$150\n$200\n$250\n$300\n$350\n$400\n$450\n$500\n$550\n$600\n$650\n140,000\n142,500\n145,000\n147,500\n150,000\n152,500\n155,000\n157,500\n160,000\n$ / UCAP MW-day \nUCAP MW\n29/30 RR\n1% lower RR\n2% lower RR\nPrice cap = $594.48\n1/2 of price cap\n101.5% of RR\n106% of RR\nLower RR shifts VRR curve to the left"},{"page":24,"startToken":7146,"endToken":7436,"text":"21 \nIf one were to assume that, as may happen in a tight market, the BRA were to clear on \nthe sloped portion of the VRR Curve, Figure 3 of the Nicholson Affidavit shows that a 1% \nshift in the Reliability Requirement could reduce the capacity price by approximately \n$120/UCAP-MW-day, and a 2% reduction could lead to a price reduction of approximately \n$120-220/UCAP MW-day, depending on the capacity the auction clears.  This translates to \napproximately $6 to $12 billion in change in total capacity costs to customers resulting from a \nhistorically “normal” level of load forecast error associated with a three-year forward period.47   \nb. \nEvidence that Capacity Resources cannot be constructed in the \nPJM Region within the current three-year cycle. \nThere are multiple pieces of evidence supporting the conclusion that, in 2026, Capacity \nResources cannot be constructed in the PJM Region within the current three-year forward \nperiod, thereby undermining the key ‘counterweight’ the Commission used in its balancing \nanalysis in 2006 to justify being willing to accept the load forecast inaccuracies inherent in a \nmulti-year forward period of RPM. \nFirst, as a threshold matter, it is worth noting that PJM itself has reached this \nconclusion.  In the PJM White Paper, PJM explained that while “[t]he three-year forward \ntimeline was originally established because it aligned with the construction schedule of many \nof the resources that could be built to meet the system’s resource adequacy needs, including \nboth combustion turbine and combined cycle gas turbine resources,” this “foundational \nassumption of the RPM design has been physically broken.”48  PJM concluded that “[t]oday, \ndue to compounding frictions in siting, permitting, supply chains and interconnection, it can \n \n47 Id. at Table 5, ¶¶30-31. \n48 PJM White Paper, at 18."},{"page":25,"startToken":7436,"endToken":7724,"text":"22 \ntake two or three times as long to build a gas resource as it does to build a hyperscale data \ncenter.”49  \nSecond, despite notable reforms to PJM’s interconnection queue that are designed to \nmake the standard Cycle study one to two years in duration, data indicates that Capacity \nResources are still experiencing significant difficulty entering service at all, let alone within \nthe three-year forward period of RPM.  For example, since 2020, approximately 24 GW of \nplanned generation with fully executed interconnection agreements have terminated their \nagreements before reaching commercial operation, including 13.5 GW of natural gas \ncapacity.50  These terminations have largely been caused by matters external to PJM, and \ncontinue to inhibit the deployment of new capacity to the PJM Region.  Indeed, in May 2026 \nPJM reported that “~53 GW of interconnection projects – enough to power 40 million homes \nat full output – currently have signed agreements to connect to the grid, but many are being \nstymied by issues beyond PJM’s control, like federal, state and local permitting, siting, and \nsupply chain challenges.”51  Additionally, as Dr. Nicholson explains, a recent analysis of \nPJM’s interconnection queue between 2015 and 2024 found that new large natural gas-fired \ngeneration projects that completed the interconnection process had an average timeline of 10.8 \nyears between initial submission into the queue and commercial operation.52  This study also \n \n49 Id.  \n50 Nicholson Affidavit, at ¶ 34. \n51 See PJM, New, Faster Generation Interconnection Process Fact Sheet (Updated May 21, 2026), \nhttps://www.pjm.com/-/media/DotCom/about-pjm/newsroom/fact-sheets/interconnection-reform-progress-fact-\nsheet.pdf.  \n52 Nicholson Affidavit, at ¶ 34 (citing Ralph O’Connor Sustainable Energy Inst., Johns Hopkins Univ., Natural \nGas Generator and Energy Storage Timelines in PJM, at 2-3 (May 18, 2026))."},{"page":26,"startToken":7724,"endToken":8020,"text":"23 \nfound that, since 2015, of 102 gas-fired generators over 100 MW that entered into the PJM \nqueue, only thirteen were online by early 2026 (eleven years later).53   \nThird, recent evidence indicates that the global shortage of gas turbines—the \ntechnology underlying RPM’s reference resource (and combined cycle gas turbine resources \nas well)—has made three-year entry functionally impossible.  As Dr. Nicholson explains, \nmajor manufacturers have reported backlogs stretching years into the future.  For example, \nSiemens Energy disclosed an approximately 69 GW order backlog as of August 2026, with \nnew orders now quoting lead times of three years or more.  GE Vernova similarly reported a \n116 GW backlog it expected to exceed 125 GW by year-end 2026, and Mitsubishi’s gas turbine \nlead times have grown from roughly two years just after the pandemic to five years or more \ntoday, with the company now booking deliveries as far out as 2031 to 2034.54   \nFourth, recent markets data and rule changes indicate the current market environment \nis no longer conducive to new resource entry within the three-year forward period of RPM.  \nThis is perhaps most clearly illustrated by the recent BRA results, which conclusively \ndemonstrate the current construct is failing to procure adequate capacity, even as prices have \nreached their regulatory ceiling.55  In particular, the 2027/2028 and 2028/2029 BRAs each \ncleared at the Commission-approved price cap (most recently $325.00/MW-day in the Rest of \nRTO zone for the 2028/2029 BRA) while simultaneously failing to procure the full Reliability \nRequirement, falling short by 6,517 MW UCAP and 6,831 MW UCAP, respectively.56  \nNotably, the 2029/2030 BRA, scheduled for December 2026, will again be subject to a price \n \n53 Id. \n54 Id., at ¶ 35. \n55 Id., at ¶ 7. \n56 Id."},{"page":27,"startToken":8020,"endToken":8312,"text":"24 \ncap, set at $337.83/UCAP MW-day.57  It is also worth noting that future auctions, beyond the \n2029/2030 Delivery Year, are slated to be run on an uncapped basis, a factor that will allow \nprices to further rise to the regulatory maximum price and that generation developers would \nnaturally incorporate into their commercial outlooks for new generation revenue.   \nAt the same time, PJM recently pursued alternative procurement mechanisms that offer \nlong-term investment certainty superior to the three-year forward period of RPM.58  \nSpecifically, the RBP, which the Commission accepted and suspended for further briefing on \nSeptember 30, 2026, would procure capacity from new resources on a pay-as-bid basis for \nterms of up to fifteen years, subject to a weighted-average price cap of $555/MW-day, for \nresources expected to be in service by June 1, 2032.59   Because a Capacity Resource that clears \nan RPM Auction is ineligible for an RBP auction, these long-term procurement mechanisms \ncompete directly with (and, given their superior revenue certainty, are likely to draw \ndevelopers away from) the three-year forward BRA, which offers only a single-year \ncommitment.60  The scale of that pull is already evident, with PJM reporting that roughly 136 \nGW of potential new capacity, spanning 397 projects and 87 entities, have expressed interest \nin RBP auctions or in facilitated bilateral matching in response to its request for interest.61  As \nDr. Nicholson explains, it is highly unlikely that a  rational investor would forgo a long-term \ncommitment of up to fifteen years under an RBP auction or potentially similar certainty under \na contract directly with a large load, in favor of a single Delivery Year’s worth of revenue \n \n57 Id., at ¶ 9. \n58 Id., at ¶ 67. \n59 Id.  \n60 See id. \n61 Id."},{"page":28,"startToken":8312,"endToken":8581,"text":"25 \ncertainty under the BRA, particularly now that lenders financing new merchant generation \ngenerally insist on exactly the kind of long-term offtake commitment that only those alternative \nmulti-year mechanisms can offer.62   \nIn summary, there is ample evidence that the risk balancing analysis the Commission \nrelied on in 2006 has collapsed in 2026.  Not only have the load forecast inaccuracies inherent \nin RPM’s three-year forward period increased considerably since 2006, but Capacity \nResources are now functionally incapable of being constructed in the PJM Region within the \ncurrent three-year cycle, leaving only the downside pricing risk of those load forecast \ninaccuracies to be borne by customers.   \nii. \nThe prospective assumptions in 2006 regarding the ability of RPM’s \nmulti-year forward period to incentivize LSE bilateral contracting and \nrisk hedging have been disproven over the course of 20 years. \nOne of the key ideas put forward in the August 2005 Initial RPM Filing was that RPM’s \nmulti-year forward period would help facilitate LSE bilateral contracting and risk hedging.  \nPJM explained that “[l]onger term price signals [] should incent longer term bilateral contracts, \nas an effective means of hedging the reliability charges assessed under RPM.”63  In support of \nthis proposition, PJM included testimony from Andrew Ott, then PJM’s Vice President of \nMarket Services.  Mr. Ott explained that this anticipated enhanced incentive for LSE bilateral \ncontracting and risk hedging would “help orient market participant objectives with the \nsystem’s reliability needs, and help ensure the long-term viability of the competitive market \nmodel in the electric industry.”64   \n \n62 See id. \n63 August 2005 Initial RPM Proposal, at 77. \n64 Id. at Ott Affidavit ¶ 15."},{"page":29,"startToken":8581,"endToken":8860,"text":"26 \nSeveral protesters raised concerns with PJM’s prognostications regarding RPM’s \npositive impact on LSE bilateral contracting and risk hedging, arguing that, contrary to PJM’s \npredictions, “RPM will impair parties’ willingness and ability to manage risk: since all parties \nwill be fully hedged prior to each Delivery Year, there will be no incentive for parties to \nmanage their own risk by entering into additional bilateral contracts.”65  Protesters further \nargued that “if the market becomes less volatile, parties will be less motivated to enter into \nbilateral agreements even before entering the capacity markets.”66 \nIn response, PJM acknowledged that “RPM will affect bilateral contracting in the PJM \nregion, just as LMP affected bilateral contracting,” but argued that “the impact will be \nbeneficial from the standpoint of system reliability, as it will encourage contracts of four years \nor more.”67 PJM argued that, under the current structure, “LSEs that have an orientation \ntowards short time horizons are not entering into long-term contracts” and that “[t]o the extent \nRPM begins to induce a change in contracting towards agreements that come closer to \nreflecting those costs and supporting those investments [necessary to maintain a reliable \nsystem], then it is a change worth making, and one the Commission should support as a matter \nof policy.”68 \nIn its April 2006 Initial Order approving RPM’s multi-year commitment period, the \nCommission accepted PJM’s assumptions and predictions regarding the incentivization of LSE \nbilateral contracting and risk hedging, stating:   \n \n \n65  April 2006 Initial Order, at P 65. \n66 Id. \n67 PJM Interconnection, L.L.C., Motion for Leave to Answer and Answer of PJM Interconnection, L.L.C, at 35 \n(Sept. 16, 2005). \n68 Id., at 35-36."},{"page":30,"startToken":8860,"endToken":9203,"text":"27 \nThe Commission does not consider it likely that RPM will \nlessen parties’ motivation to purchase more of their forward-\nlooking capacity needs through bilateral contracts, or to \nmanage their risk in other ways, such as releasing or \npurchasing additional capacity in the auctions following the \nResidual Base Auction during the four years prior to each \nDelivery Year.  First, those states or LSEs who wish to maintain \nmaximum flexibility to manage their own risk will be able to \nfulfill their own capacity needs by providing their own fixed \nresource requirement.  Second, as PJM has alleged, parties are \nnot engaging in significant amounts of forward contracting \nnow: RPM will provide more information to all market \nparticipants, and all parties will be able to use this information \nto manage their risk more effectively, whether through \nbilateral contracting or otherwise.  Moreover, the series of \nfollow-on auctions for each Delivery Year will enable LSEs to \nadjust the amounts of capacity they hold, or to seek to obtain \ncapacity at a better price, until four months before the Delivery \nYear.69 \nThese prospective predictions and assumptions made in 2006 regarding the impact of \nRPM’s multi-year forward period on LSE bilateral contracting and risk hedging have been \ncomprehensively disproven over the course of 20 years.  The anticipations of PJM and the \nCommission, that RPM would lead to a broad propagation of bilateral contracting and hedging, \nand the associated reasoning used in support of accepting the three-year forward period, have \nnot come to pass.  This conclusion is supported by several pieces of evidence.   \nFirst, PJM itself identified that a significant portion of PJM load is presently served by \nentities that rely on short-term procurement rather than long-term bilateral contracts to meet \ntheir capacity needs, leaving those entities (and the retail customers they serve) directly \nexposed to RPM price volatility, rather than hedged against it. And, as a corollary, \nopportunities for long-term contracting between those entities and Capacity Resources have \nbeen equally limited.  In the PJM White Paper, PJM explained that: \n \n69 April 2006 Initial Order, at P 70 (emphasis added)."},{"page":31,"startToken":9203,"endToken":9611,"text":"28 \nA significant portion of PJM load is served by default service \nproviders – state-regulated entities that are often constrained by \nstatute or regulatory practice from entering long-term bilateral \ncontracts. These entities procure capacity primarily through \nshort-term default service auctions calibrated to the annual \nBase Residual Auction cycle. During PJM’s prolonged surplus \nera, this approach was rational: short-term procurement \ncaptured low market prices without paying a long-term hedge \npremium. But it also left these entities – and their retail \ncustomers – exposed to capacity price volatility when the market \ntransitioned into scarcity. This effect was exacerbated by the \npersistent capacity auction delays experienced in PJM.70 \nSimilarly, in PJM’s February 2025 filing to establish a revised price cap and price floor \nfor the 2026/2027 and 2027/2028 Delivery Years, PJM’s Executive Vice President for Market \nServices and Strategy Stu Bresler explained that although the RPM was initially expected to \nbe a residual market, with the majority of capacity contracted bilaterally, that contracting has \nnot occurred.  Instead, Mr. Bresler explained that “[r]ather, it appears that substantial load in \nthe states that have expressed concern are directly exposed to Base Residual Auction prices for \nthe entirety of their capacity obligations.”71  It was precisely because of this absence of long-\nterm contracting that PJM presented “Path A” in the PJM White Paper, which envisions \nenhanced requirements for LSEs to sign long-term capacity contracts to support investment in \nnew capacity resources and to act as a hedge against volatility in capacity market prices.72  \n \n70 PJM Whitepaper, at 29-36.  \n71 PJM Interconnection, L.L.C., Affidavit of Mr. Frederick S. Bresler III on Behalf of PJM Interconnection, \nL.L.C., at 6, Docket No. ER25-1357-000 (Feb. 20, 2025), emphasis added (“The original vision of the RPM was \nfor it to function primarily as a residual market, with the majority of capacity procured through bilateral contracts \nand only a small portion needed to cover remaining needs from the market. Participation in this way as originally \nintended would serve to substantially hedge market participants on both the supply and demand sides from \nuncertain and potentially volatile Base Residual Auction clearing prices. The historic and existing capacity market \ndesign and results do not appear to have sufficiently stimulated this type of activity. Rather, it appears that \nsubstantial load in the states that have expressed concern are directly exposed to Base Residual Auction prices \nfor the entirety of their capacity obligations.”). \n72 PJM Whitepaper, at 32-34."},{"page":32,"startToken":9611,"endToken":9919,"text":"29 \nSecond, in many PJM jurisdictions, LSEs are restricted by state law from engaging in \nthe kinds of long-term bilateral contracting and hedging that the Commission envisioned in \n2006 when approving the three-year forward period of RPM.  Exelon Affiant Deborah Sears \nsubmits direct testimony on this point into the record, describing in detail the range of \nrestrictions on long-term bilateral contracting and hedging in the District of Columbia, \nMaryland, New Jersey, and Delaware.  As Ms. Sears notes, “[t]he SOS/BGS auction structures \nare highly prescriptive and any changes to the annual auction process are reviewed through a \nstakeholder meeting called the Procurement Improvement Process, and the final changes to the \nRequest for Proposal and Full Requirements Service Agreement require approval by the \napplicable state utility regulatory commission.”73  As Ms. Sears puts plainly, “Pepco, DPL, \nand ACE are not permitted to enter into any bilateral transactions including hedging \nagreements without approval from the applicable state utility regulatory commission.”74   \nThird, beyond restrictions in state law, restrictions in federal law have also been \nidentified by certain states as an obstacle to long-term bilateral contracting and hedging.  To \nthis point, and as further referenced by Dr. Nicholson, a New Jersey Board of Public Utilities \n(“NJBPU”) examination of the PJM capacity market explained that federal legal restrictions \nlimit the types of bilateral contracting the state of New Jersey can engage in to procure capacity \nbilaterally on a long-term basis outside of the RPM.75  The NJBPU assessment found that \n“[t]he only way an LSE can use capacity procured wholly outside the RPM to meet its capacity \nneeds is by electing to use the Fixed Resource Requirement (“FRR”) Alternative under which \n \n73 Sears Affidavit, at ¶ 9.  \n74 Id.   \n75 Nicholson Affidavit, at ¶ 38 (citing New Jersey Board of Public Utilities, An Investigation of PJM’s Capacity \nMarket, at 6 (Aug. 2026))."},{"page":33,"startToken":9919,"endToken":10229,"text":"30 \nit must meet all of its capacity needs outside of the RPM for the relevant service area.  \nHowever, the Reliability Assurance Agreement effectively bars LSEs in states like New Jersey \nthat allow full retail choice from electing the FRR Alternative.”76  The Assessment went on to \nexplain that the state of New Jersey attempted to make long-term bilateral capacity \nprocurements through the Long-Term Capacity Pilot Program, but courts found the program \nwas preempted by the Federal Power Act in PPL v. Hannah77 and PPL v. Solomon.78  The \nNJBPU further explained that Hughes v. Talen79 put further limits on the types of long-term \nbilateral capacity contracting PJM states can engage in.  As a result of these federal legal \nconstraints, NJBPU concluded that “to date New Jersey LSEs have opted to procure the \ncapacity they needed exclusively or nearly exclusively through RPM auctions.”80   \nIn summary, the prospective assumptions and predictions of PJM and the Commission \nin 2006 regarding the ability of RPM’s multi-year forward period to incentivize LSE bilateral \ncontracting and risk hedging have not come to pass over the last 20 years. \niii. \nThe current three-year forward period inhibits efficient resource exit \nand Deactivation, as it requires generation owners to invest in the \nabsence of reasonable predictability in future operational capability \nand environmental policy.   \nUnder PJM’s Capacity Performance construct, cleared Capacity Resources with RPM \ncommitments are required to be available to operate throughout the Delivery Year, pursuant to \nRPM’s must-offer requirements.  Capacity Resources have particular performance obligations \nwhen scheduled and/or dispatched by PJM during a Performance Assessment Interval \n \n76 Id. \n77 PPL Energyplus, LLC v. Hanna, 977 F.Supp. 2d 372, 389-390 (D.N.J. 2013).  \n78 PPL EnergyPlus, LLC v. Solomon, 766 F.3d 241, 246 (3rd Cir. 2014). \n79 Hughes v. Talen Energy Mktg., LLC, 578 U.S. 150 (2016).  \n80 Nicholson Affidavit, at ¶ 38."},{"page":34,"startToken":10229,"endToken":10531,"text":"31 \n(“PAI”).81  Capacity Resources that fail to perform when called upon face severe financial \npenalties, or as PJM has described it, “[g]enerators assume virtually all financial risks if they \ndo not meet their power supply obligations.”82 \nIn deciding how to bid their Capacity Resources into RPM and at what price, all \nresource owners must engage in a business risk balancing analysis that weighs the potential \nrevenues that might be earned in a given RPM Auction against the cost of continuing to operate \na given Capacity Resource, including the Capacity Performance risk associated with failing to \nperform when called upon during a PAI.  Indeed, PJM’s rules explicitly acknowledge these \nconsiderations in the construction of a resource’s Avoidable Cost Rate (“ACR”), which \nrepresents the ongoing fixed operation and maintenance costs a Capacity Resource can avoid \nif it does not operate for a given Delivery Year, and in a resource’s Capacity Performance \nQuantifiable Risk (“CPQR”), which measures and values the expected financial risks and \npotential performance penalties that a Capacity Resource may face during emergency \noperations. \nFor the owners of older Capacity Resources that may be trying to ascertain whether it \nis economic to remain in the market or exit through Deactivation, the three-year forward period \nof RPM profoundly clouds this balancing analysis.  The reason for this is simple—these \nresource owners cannot see three years (and in practice, four years) into the future.  As a result, \nthey are unable to make two important determinations: (i) whether they will be able to \nphysically operate their resource dependably during the future Delivery Year; and (ii) whether \n \n81 See Tariff, Attachment DD, Section 5.5A(a). \n82 See PJM Interconnection, Capacity Performance at a Glance (last visited Sept. 27, 2026), \nhttps://www.pjm.com/-/media/DotCom/library/reports-notices/capacity-performance/20150720-capacity-\nperformance-at-a-glance.ashx?la=en."},{"page":35,"startToken":10531,"endToken":10838,"text":"32 \napplicable environmental policy will legally allow them to operate their resource during the \nfuture Delivery Year.  Furthermore, given the various uncertainties in play, Capacity Resource \nowners may also struggle to predict future system conditions and therefore estimate the volume \nof Capacity Performance exposure.  Accordingly, even if it would be efficient for the market, \neconomic for the resource owner, and beneficial to reliability as a whole for the Capacity \nResource to remain in the market, these resource owners are incapable of conducting an \naccurate risk assessment and are thus inadvertently incentivized to exit the market earlier than \nmay be appropriate.  These operational and environmental policy uncertainties are described \nbelow, in the following subsections IV.A.iii.a and IV.A.iii.b. \na. \nOperational Uncertainties \nA key consideration for the owner of a Capacity Resource contemplating Deactivation \nis whether they will be physically able to dependably operate their resource during the future \nDelivery Year.  By definition, many of the resources contemplating Deactivation are old and \nnearing the end of their operational life.  This reality tends to exacerbate several factors critical \nto the predictability of future operations.  The first is the availability and long-term \nprocurement of fuel.  Global instability, supply chain disruptions, transportation and storage \nbottlenecks, and contractual rigidity in price/volume take, duration, and collateral credit \nrequirements can make accurately forecasting the price and future availability of both the fuel \ncommodity itself and delivery challenging, particularly for resources that may be operating \nunder shorter time horizons due to their vintage. \nThe second factor that can exacerbate uncertainty around the future ability of an older \nCapacity Resource to operate is project investment.  These facilities tend to need significant \ninvestment in their physical plant to continue reliable operations when compared to newer \nfacilities.  In PJM, this fact can be seen in the scale of identified project investment for units"},{"page":36,"startToken":10838,"endToken":11130,"text":"33 \nthat are required to continue operations via Reliability Must-Run (“RMR”) arrangements with \nthe RTO.  For example, in its April 18, 2024, application for cost recovery for the Brandon \nShores facility in Maryland, Talen Energy identified nearly $30,000,000 in anticipated project \ninvestment to ensure the availability of the facility for PJM scheduling and dispatch.83   \nFinally, employee retention has remained an ongoing challenge for resource owners, \nas an aging workforce and the geographic isolation of many power plants limits the availability \nof skilled personnel needed to operate these facilities, particularly as they near the end of their \nuseful life.  Additionally, competition for the labor skill sets required to operate power plants \nis also increasing from other sectors of the economy.  To this point, the Department of Energy \nin its 2026 United States Energy and Employment Report, (“USEER”) found that “energy \nemployers are increasingly competing for workers not only with other energy companies, but \nalso with fast-growing data centers, infrastructure projects, advanced manufacturing facilities, \nand critical minerals industries” as “[t]hese sectors rely on many of the same skilled \noccupations, including electricians, electrical engineers and technicians, industrial \nmaintenance workers, construction trades workers, and production workers.”84  These \nchallenges can add to uncertainty regarding the staffing needed to ensure the operational \navailability of Capacity Resources in the future. \nb. \nEnvironmental Policy Uncertainties \nIn addition to the operational uncertainties described above, a key consideration for the \nowner of a Capacity Resource contemplating Deactivation is whether they will be able to \n \n83 Brandon Shores LLC, Continuing Operations Rate Schedule of Brandon Shores LLC, Docket No. ER24-1790-\n000, at 18 (Apr. 18, 2024). \n84 U.S. Dep’t of Energy, 2026 United States Energy and Employment Report, at 24 (2026), \nhttps://www.energy.gov/documents/2026-useer-national-report."},{"page":37,"startToken":11130,"endToken":11205,"text":"34 \nlegally operate their resource, and under what environmental regulations, during the future \nDelivery Year.  Environmental regulations at both the federal and state level directly impact \nthe operation of Capacity Resources, and can change significantly from year to year. \nFor example, federal environmental policy has been particularly volatile in recent \nyears, as reflected in Figure Exelon-1, which illustrates the major changes to federal carbon \ndioxide regulation policy that have occurred just over the last decade."},{"page":38,"startToken":11205,"endToken":11577,"text":"35 \nFigure Exelon-1 \nMajor Changes in Federal Regulation of Carbon Dioxide \n2015-2026 \nDate \nFederal Carbon Dioxide Regulation Event \nAugust 3, 2015 \nThe EPA finalizes the Clean Power Plan, which aims to reduce \ncarbon dioxide emissions from the power sector by 32% below 2005 \nlevels by 2030.85 \nFebruary 9, 2016 \nThe United States Supreme Court stays the implementation of the \nClean Power Plan, pending further proceedings before the United \nStates Court of Appeals for the District of Columbia Circuit (“D.C. \nCircuit”).86 \nJune 19, 2019 \nThe EPA finalizes the Affordable Clean Energy Rule, which repeals \nthe Clean Power Plan.87 \nJanuary 19, 2021 \nThe D.C. Circuit vacates the Affordable Clean Energy Rule.88 \nJune 30, 2022 \nThe United States Supreme Court rejects EPA’s attempt to revive \nthe Clean Power Plan, and limits EPA’s ability to regulate carbon \ndioxide emissions from power plants under the Clean Air Act.89  \nApril 25, 2024 \nThe EPA announces final Carbon Pollution Standards requiring that \nall long-term coal-fired plants and base load new gas-fired plants \ncontrol 90% of their carbon emissions.90 \nSeptember 17, 2026 \nThe EPA repeals most of the Carbon Pollution Standards and \nsolicits comment on additional reasons to rescind all greenhouse gas \nemission requirements for fossil fuel-fired generators.91 \n \n \n85 See U.S. Env’t Prot. Agency, Fact Sheet: Overview of the Clean Power Plan (last updated May 9, 2017), \nhttps://archive.epa.gov/epa/cleanpowerplan/fact-sheet-overview-clean-power-plan.html \n86 \nSee \nChamber \nof \nCommerce \nv. \nEPA, \n136 \nS. \nCt. \n999 \n(2016) \n(order \ngranting \nstay), \nhttps://www.supremecourt.gov/orders/courtorders/020916zr3_hf5m.pdf. \n87 See U.S. Env’t Prot. Agency, Affordable Clean Energy (last updated Mar. 12, 2026),  \nhttps://www.epa.gov/stationary-sources-air-pollution/affordable-clean-energy-rule. \n88 Am. Lung Assoc. v. EPA, 985 F.3d 914 (D.C. Cir. 2021). \n89 W. Va. vs. EPA, 597 U.S. 697 (2022). \n90 See U.S. Env’t Prot. Agency, Supporting Information – Final Greenhouse Gas Standards and Guidelines for \nFossil Fuel-Fired Power Plants (last updated May 20, 2026), https://www.epa.gov/stationary-sources-air-\npollution/supporting-information-final-greenhouse-gas-standards-and. \n91 See Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units, 91 Fed \nReg. 58,954 (Sept. 17, 2026), https://www.federalregister.gov/documents/2026/09/17/2026-19071/partial-repeal-\nof-the-carbon-pollution-standards-for-fossil-fuel-fired-electric-generating-units."},{"page":39,"startToken":11577,"endToken":11881,"text":"36 \nThe impact of federal environmental policy can also be seen in the words of PJM \nresource owners themselves, through their Deactivation notices to PJM.  For example, in its \nJuly 22, 2025, Deactivation notice to PJM for the Kincaid facility, Vistra Corp. explained that \n“[t]he Kincaid Units will cease operations by this date in order to comply with the U.S. \nEnvironmental Protection Agency’s (EPA) Coal Combustion Residual (CCR) Rule, 40 C.F.R. \nPart 257, Subpart D.”92 \nBeyond federal environmental policy, uncertainty and future assumptions regarding \nstate environmental policy can also impact Deactivation decisions.  Indeed, a review of \ngenerator Deactivation notices in PJM from the last three years makes clear that prospective \nassumptions regarding the future applicability of state environmental regulations are a key \ndriver for Deactivation decisions in the PJM Region, as illustrated in Figure Exelon-2.   \nFigure Exelon-2 \nReferences to State Environmental Regulations in PJM Deactivation Notices \n2023-2026 \nDeactivation \nLetter \nDate \nReason Given in Deactivation Letter \nCumberland \nCT \nAugust \n26, 2024 \n“Calpine’s Cumberland CT 1 generating facility in its current \nstate will be physically unable to perform in the Delivery Year \n2027/2028 as a result of finalized regulations in connection \nwith New Jersey’s efforts to limit carbon emissions from \npower plants.” \nSherman \nAvenue \nAugust \n26, 2024 \n“Calpine’s Sherman Avenue generating facility in its current \nstate will be physically unable to perform in the Delivery Year \n2027/2028 as a result of finalized regulations in connection \nwith New Jersey’s efforts to limit carbon emissions from \npower plants.” \n \n92 Vistra’s July 22, 2025, Deactivation Letter is available on the PJM Website.  See Deactivation Notice Letter \nfor Kincaid Generation, L.L.C, from Jessica H. Miller, Vice President & Assoc. Gen. Counsel, Vistra Corp., to \nPJM \nGeneration \nManager \n(July \n22, \n2025), \nhttps://www.pjm.com/-/media/DotCom/planning/gen-\nretire/deactivation-notices/kincaid-deactivation-letter.pdf."},{"page":40,"startToken":11881,"endToken":12284,"text":"37 \nElwood \nMay 28, \n2024 \n“Given current and expected market conditions and ongoing \nIllinois regulatory uncertainty, operation of Elwood is \nexpected to continue to be uneconomic.”  \nFisk \nJune 30, \n2026 \n“Pursuant to the Illinois Climate and Equitable Jobs Act \n(“CEJA”), the Units are required to “permanently reduce all \nCO2e and copollutant emissions to zero, including through \nunit retirement” by January 1, 2030. As such, MWG intends to \nretire the Units on January 1, 2030.”  \nElgin \nMay 10, \n2024 \n“MRP Elgin is planning to retire the Units as of June 1, 2025 \nin light of PJM market conditions and operating restrictions \nimposed by the stringent emissions limits under the Illinois \nClimate and Equitable Jobs Act. Given these circumstances, \ncontinued operation of the Units is expected to be uneconomic \nrelative to other opportunities.” \nZion  \nJune 22, \n2026 \n“Constellation intends to retire these units in compliance with \nthe Illinois Climate and Equitable Jobs Act (CEJA), which \nrequires certain electric generation resources to reduce all \nCO2 and co-pollutant emissions to zero, including through \nunit retirement, on or before January 1, 2030.” \nSayreville \nDecember \n29, 2023 \n“The New Jersey Department of Environmental Protection \n(NJDEP) issued a final regulation on January 3, 2023 \nestablishing CO2 emissions rates limits for in-state electric \ngenerating units (EGUS) sized 25 MW and larger. The \nSayreville units are unable to operate within the limitation that \ngo into effect on June 1st, 2024, 1,700 lbs CO2/MWh. These \nnew regulations will require New Jersey-located EGUs to \nretire if they are unable to meet the established CO2 emissions \nrates limits unless granted a reliability extension by the \nNJDEP.” \nBrandon \nShores  \nApril 6, \n2023 \n“The Brandon Facilities’ National Pollution Discharge \nElimination System (“NPDES”) permit precludes operation \nusing coal on or after January 1, 2026. Brandon had \npreviously been evaluating a conversion of the Brandon \nFacilities to fuel oil combustion but has determined that, \nunder current capacity market rules, such a conversion is \nuneconomic and does not justify operating after June 1, 2025. \nThe Brandon Facilities have capacity market obligations \nthrough May 31, 2025.” \nH.A. Wagner  October \n16, 2023 \n“The Wagner Facilities’ Title V air permit limits operation to \ncapacity factors under 15% when operating on oil. The limited \nrun hours on the Wagner Facilities are not sustainable to \ncontinue operations, especially in light of the amount of time \nthe Wagner Facilities have recently been running in the \nmarket. The combination of low margin energy market"},{"page":41,"startToken":12284,"endToken":12664,"text":"38 \neconomics, low-capacity prices and significant Capacity \nPerformance penalty risk due to run hour limitations results in \nthe economics being outweighed by the risk associated with \ncontinued operation. The Wagner Facilities have capacity \nmarket obligations through May 31, 2025.” \nCardinal \nJuly 22, \n2026 \n“[U]nless and until such conditions are satisfied, or waived by \nBuckeye in its discretion, continued operations past December \n31, 2028, will not be possible based on the requirements of the \nEPA NOPP and the Sierra Club Agreement. Should these \nconditions be satisfied, or waived by Buckeye in its discretion, \nBuckeye reserves the right to withdraw its deactivation notice \nand participate in future PJM capacity auctions for the \n2029/2030 Delivery Year and thereafter.” \nUniversity \nPark North \nStation \nJune 30, \n2026 \n“LSPUP is deactivating these units due to uneconomic \ncompliance requirements of the Illinois Climate and Equitable \nJobs Act.”  \nRocky Road \nFebruary \n6, 2026 \n“Dairyland intends to retire the Unit due to its inability to \nmeet operational restrictions imposed on the Unit by the Clean \nAir Act Permit Program (“CAAPP”) permit issued by the \nIllinois Environmental Protection Agency (“EPA”).” \nForked River \n1 \nFebruary \n24, 2025 \n“Forked River’s Unit-1 generating facility in its current state \nwill be physically unable to perform in the Delivery Year \n2027/2028 as a result of finalized regulations in connection \nwith New Jersey’s efforts to limit carbon emissions from \npower plants. Thus, as affirmed by this submission, Forked \nRiver plans to retire the Unit-1 generating facility before the \ncommencement of the 2027/2028 delivery year and provides \nthis Notice of Deactivation.” \nForked River \n2 \nFebruary \n24, 2025 \n“Forked River’s Unit-2 generating facility in its current state \nwill be physically unable to perform in the Delivery Year \n2026/2027 because of its inability to meet NJ air permit \nrequirements. Thus, as affirmed by this submission, Forked \nRiver plans to retire the Unit-2 generating facility before the \ncommencement of the 2026/2027 delivery year and provides \nthis Notice of Deactivation.” \n \nGiven the outsized role that prospective assumptions regarding the future applicability \nof operational and environmental policy play in Deactivation decisions in the PJM Region, the \nstability and veracity of those assumptions are, by extension, critical to the determination of \nwhether or not a Deactivation decision is efficient for the market and economic for the resource"},{"page":42,"startToken":12664,"endToken":12984,"text":"39 \nowner in the context of RPM’s three-year forward period.  And therein lies the problem.  Given \nthe protean nature of the operational uncertainties and environmental policy considerations \ndescribed above, a three-year forward period is often too long for resource owners to develop \nconfidence that they will be permitted to continue operation of their Capacity Resources in the \nfuture.  The decision these resource owners are left with in light of that ambiguity is simple—\nexit the market to avoid significant and hard-to-predict regulatory risks, even if it might \notherwise be efficient for the market and economic for the resource owner to stay. \nImportantly, the uncertainty in operational availability and environmental policy \ndescribed above also incentivizes the owners of Capacity Resources that remain in the market \nto include a “risk premium” in their RPM offers, especially when the auction is run three years \nforward.  As Dr. Nicholson explains, under PJM’s Capacity Performance construct, this \nuncertainty is reflected in a resource’s CPQR component of a capacity sell offer, meaning that \nthe three-year forward period directly inflates the risk premium that owners of resources near \nthe end of their economic life must build into their capacity supply offers, or exit the market \nrather than attempt to price that risk at all.93  This dynamic is not unique to PJM.  As ISO-NE \nexplained in proposing a prompt capacity auction, “the uncertainty about whether a new or \nexisting resource will be available to perform three years into the future can be reflected in \nsuppliers’ capacity offers or bids through higher risk premiums, increasing Capacity Clearing \nPrices over what those prices would have been had the auction been held closer in time to the \nCapacity Commitment Period, where sellers would have more certainty about their \nperformance and the costs associated with holding an obligation.”94 \n \n93 Nicholson Affidavit, at ¶¶ 40-43. \n94 Id. at ¶ 41 & n. 63 (citing ISO-NE Transmittal, Docket No. ER26-925, at 24 (December 30, 2025))."},{"page":43,"startToken":12984,"endToken":13265,"text":"40 \nIn summary, the current three-year forward period inhibits efficient resource exit and \nDeactivation, as it requires generation owners to take on capacity commitments and make \ncapital investments in the absence of reasonable predictability in future operational capability \nand environmental policy.  It also leads to higher capacity prices by causing the owners of \nCapacity Resources to include a “risk premium” in their RPM offers to account for these \nuncertainties. \niv. \nPJM’s current capacity accreditation methodology (ELCC) bears no \nresemblance to the eFORd model considered by the Commission in \n2006, and the three-year forward period forces PJM to integrate \nspeculative assumptions into its ELCC modeling. \nAt the time of the Commission’s 2006 approval of RPM’s multi-year forward period, \nPJM used a capacity accreditation methodology known as Equivalent Forced Outage Rate - \ndemand, or “eFORd.”  This methodology focused on historic, unit-specific metrics that \nmeasured the percentage of time that a specific unit was forced out of service or unable to run \nwhen called upon.  For various reasons, including the nature of the then-prevailing generation \nmix and the types of operational risks faced by the PJM Region, eFORd was supportable when \nRPM was accepted.  Additionally, because eFORd relied on a resource’s own historical \nperformance rather than on system-wide, forward-looking modeling of the resource mix, it had \na high level of predictability, stability, and replicability for resource owners. \nOn July 30, 2021, the Commission accepted PJM’s proposal to transition from eFORd \nto a new capacity accreditation methodology, known as Effective Load Carrying Capability  \n(“ELCC”).95  Unlike eFORd, ELCC considers the simultaneous reliability contribution of all \nresources, and recognizes the complementary and antagonistic interactions among the \n \n95 PJM Interconnection, L.L.C., 176 FERC ¶ 61,056 (2021)."},{"page":44,"startToken":13265,"endToken":13559,"text":"41 \nresources expected to be able to provide capacity in a given Delivery Year.  In general, a \nresource that contributes a significant level of capacity during high-risk hours (i.e., hours with \nvery high electricity demand and low resource output) will have a higher capacity value under \nELCC than a resource that delivers the same generating capability but only during low-risk \nhours.  These risk hours may vary as the resource mix changes (e.g., more wind and solar \nresources are installed) and hours of high demand evolve (e.g., wide-scale electric car charging \nat night).96   \nAs explained by Dr. Nicholson, the process by which PJM implements the ELCC \nmodel involves an extraordinary amount of data and analysis.97  Specifically, ELCC class \naccreditations are derived from sophisticated probabilistic modeling that estimates each \nresource class’s reliability contribution across a wide range of system conditions, placing the \ngreatest weight on the hours of greatest reliability risk, and PJM must update and re-run this \nanalysis as the assumed resource mix and load profile change from year to year.98 \nGiven the volume of data and analytical complexity involved in implementing the \nELCC model, the accuracy and replicability of PJM’s ELCC model has remained an issue of \nparamount concern within the PJM Region since the model’s inception in 2021.  These \nconcerns have been expressed directly to the PJM Board by the Organization of PJM States, \nInc. (“OPSI”), with OPSI arguing that “[t]he accuracy of the ELCC methodology is essential \nand necessary to ensure that it reflects the true ability of supply to meet demand and secure the \n \n96 PJM’s current ELCC methodology is set forth in RAA, Schedule 9.2 and implemented through PJM Manuals \n21A and 21B.  \n97 Nicholson Affidavit, at ¶¶ 44-50. \n98 Id., at ¶ 47."},{"page":45,"startToken":13559,"endToken":13886,"text":"42 \nreliability needs of the region.”99  Indeed, in its August 4, 2025, letter approving the Forecast \nPool Requirement (“FPR”) and the Installed Reserve Margin (“IRM”) for the 2027/2028 \nDelivery Year BRA, the PJM Board acknowledged that at the Markets and Reliability \nCommittee (“MRC”) and Members Committee (“MC”) “[a]dditional concerns were expressed \nabout the methodology utilized to determine Effective Load Carrying Capability (ELCC) \nvalues that are derived from the same reliability analysis that produces the FPR and IRM.”100  \nThe Board accordingly directed PJM to engage a consultant to examine the ELCC \nmethodology to identify improvements.  The consultant’s report was published in December \n2025,101 and included multiple recommendations regarding how to enhance transparency and \naccuracy.  \nYet the current three-year forward period of RPM works against model accuracy and \nreplicability by forcing PJM to integrate assumptions that are almost certain to change over the \ncourse of three years.  As explained by Dr. Nicholson, under ELCC PJM must estimate the \nresource mix that will actually be available during the Delivery Year (including the mix of \nthermal, intermittent, and storage resources expected to be in service, and the retirements and \nnew entry assumed to occur before that year) approximately three and a half years before the \nstart of the Delivery Year, because capacity suppliers must know their accreditation values \n \n99 Letter from Emile Thompson, President, Org. of PJM States, Inc., to David Mills, Chair, PJM Bd. of Managers, \n& Manu Asthana, President & CEO, PJM Interconnection, L.L.C.,  at 2 (Aug. 28, 2025), https://www.pjm.com/-\n/media/DotCom/about-pjm/who-we-are/public-disclosures/2025/20250828-opsi-letter-re-consultant-review-of-\nelcc-methodology.pdf. \n100 Letter from David E. Mills, Chair, PJM Bd. of Managers, to PJM Stakeholders, at 1 (Aug. 4, 2025),  \nhttps://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-disclosures/2025/20250804-board-\ncorrespondence-re-irm-and-fpr.pdf. \n101 Energy+Environmental Economics, PJM ELCC/ RRS Model Evaluation: Prepared for PJM (Dec. 2025),  \nhttps://www.pjm.com/-/media/DotCom/committees-groups/task-forces/elccstf/2025/20251209/20251209-item-\n02---pjm-elcc-rrs-model-evaluation---e3-report.pdf."},{"page":46,"startToken":13886,"endToken":14082,"text":"43 \nbefore the BRA.102  These assumptions are far from static: PJM’s own preliminary ELCC \nestimates show that accreditation values for a given resource class can shift materially from \none year’s estimate to the next, with storage resource ELCC values in particular projected to \ndecline significantly across upcoming Delivery Years as PJM’s assumptions about extended \ncold-weather charging constraints evolve, and with the gas combustion turbine reference class \nalso experiencing meaningful changes.  This dynamic can be seen in Figure 4 of the Nicholson \nAffidavit, which shows the final ELCC values for Delivery Years 2028/2029 and 2029/2030 \nalong with PJM’s preliminary estimate for Delivery Years 2030/2031 and 2031/2032.  \nNicholson Affidavit - Figure 4  \nActual and Preliminary ELCC Values, Delivery Years 2028/29 Through 2032/33 \n \nFigure 4 of the Nicholson Affidavit illustrates just how much projected and actual \nELCC values can change over the three-year forward period of RPM depending on the \n \n102 Nicholson Affidavit, at ¶ 46. \n0%\n10%\n20%\n30%\n40%\n50%\n60%\n70%\n80%\n90%\n100%\n2028/29\n2029/30\n2030/31\n2031/32\n2032/33\nPreliminary ELCC calculation\nDelivery Year\n4-hr Storage\n6-hr Storage\n8-hr Storage\n10-hr Storage\nGas CC\nGas CT"},{"page":47,"startToken":14082,"endToken":14373,"text":"44 \nassumptions used, such as the assumed resource mix and system loads.  Because even modest \nshifts in ELCC accreditation can translate into substantial swings in a resource’s qualifying \ncapacity, and, in the aggregate, in the auction’s supply curve and clearing price, basing those \naccreditation values on three-and-a-half-year-old assumptions introduces significant \ninaccuracy into the BRA that a shorter forward period would not.103  Owing to the resulting \ninaccuracies, BRA prices can diverge from what underlying supply and demand fundamentals \nwould otherwise produce, rendering the current three-year forward period unjust and \nunreasonable.  \nv. \nThe current three-year forward period undermines the accuracy of \nother BRA planning parameters, including the assumed resource mix in \neach Locational Deliverability Area used to calculate CETO/CETL \nvalues, leading to unjust and unreasonable results.  \nThe planning parameters used in a given BRA play a critical role in the auction’s \noutcome.  For example, RPM utilizes an administratively set demand curve—the Variable \nResource Requirement Curve (“VRR Curve”)—which represents the prices that consumers \nshould be willing to pay for varying quantities of capacity.   In developing the demand curve \nfor a given BRA, PJM forecasts the expected peak load for a particular Delivery Year and then \nsets a target level of capacity needed to reliably serve the load—also known as the Reliability \nRequirement—given the expected resource portfolio.  The auction’s supply curve is based on \nSell Offers for capacity that Capacity Market Sellers submit at a specific price and, together, \nthe offers comprise the auction’s supply curve.  RPM is a locational market, meaning there are \ndefined areas within the PJM Region that have limits on the amount of capacity they can \nimport.  Those areas are LDAs, which recognize and quantify the locational value of capacity \n \n103 Id., at ¶¶ 46, 49-50."},{"page":48,"startToken":14373,"endToken":14675,"text":"45 \nwithin the PJM Region.  As relevant here, the modeled LDAs are determined by comparing \nthe import limit of an LDA (CETL) with the amount of capacity that needs to be imported into \na LDA to meet the reliability criterion (CETO).  Sell Offers are located in specific LDAs based \non where those resources are located. \nThe accuracy of the planning parameters used in a given auction are only as good as \nthe data upon which they are based.  As Dr. Nicholson explains, the three-year forward period \nundermines the accuracy of certain planning parameters, including CETO and CETL, because \nthese values depend on assumptions about the resource mix and transmission topology that \nwill actually exist in each LDA during the Delivery Year.104  As with the ELCC and load \nforecast inputs discussed above, these assumptions are far less reliable when projected three \nand a half years in advance than when set closer to the Delivery Year.  These inaccuracies and \nuncertainties introduced into the CETO and CETL parameters can, in turn, lead to capacity \nprices that do not reflect market fundamentals in the Delivery Year by misrepresenting the \ntransmission system’s ability to transfer capacity.105  This can lead to unjust and unreasonable \noutcomes.  Indeed, the idea that inaccurate planning parameters can warp the outcome of a \ngiven BRA and disassociate it from basic market fundamentals is unfortunately not an \nacademic one.  In December 2022, PJM discovered that certain Planned Generation Capacity \nResources and planned Intermittent Resources in the DPL South LDA did not offer into the \n2024/2025 Delivery Year BRA, notwithstanding the fact that such resources were included by \nPJM years earlier in the modeling assumptions (CETO) that formed the DPL South LDA \nReliability Requirement.  The absence of these resources from the 2024/2025 BRA resulted in \n \n104 Id., at ¶ 52. \n105 Id."},{"page":49,"startToken":14675,"endToken":14972,"text":"46 \nan overstated LDA Reliability Requirement, and led to a dramatically higher clearing price \nthat was wholly unrepresentative of the actual capacity needs of the LDA.106  As the \nIndependent Market Monitor (“IMM”) described it, the clearing prices for DPL South “do not \nreflect the actual market supply and demand fundamentals, overstate the local reliability \nrequirement, serve no useful purpose, and are therefore unjust and unreasonable.”107 \nAccordingly, the three-year forward period of RPM is unjust and unreasonable, because \nit undermines the accuracy of important BRA planning parameters, including the assumed \nresource mix in each LDA used to calculate CETO/CETL values, leading to market outcomes \ndivorced from underlying supply and demand conditions. \nB. \nThe Commission Should Adopt a Prompt Auction Schedule as the Just and \nReasonable Replacement Rate. \nIn the event that the Commission finds the three-year forward period of RPM to be \nunjust, unreasonable, unduly discriminatory or preferential under FPA section 206, Exelon \nproposes the Commission direct PJM to adopt as a replacement rate a “prompt” BRA schedule, \nto run two months before a given Delivery Year, starting with the 2030/2031 Delivery Year \nBRA, currently scheduled for May 2027, and beyond.  The Commission need not treat this \nproposal as novel or untested.  To the contrary, the Commission has already found, on at least \nthree occasions—for all of the other centralized capacity market structures in its jurisdiction—\nthat a prompt capacity auction schedule is just and reasonable.  Most recently, on March 30, \n2026, the Commission accepted ISO-NE’s proposal, filed jointly with the New England Power \nParticipants Committee, to replace its three-year forward capacity market with a prompt \n \n106 See generally Docket No. ER23-729-000. \n107 PJM Interconnection, L.L.C., Comments of the Independent Market Monitor of PJM, Docket No. ER23-729-\n000 (Jan. 20, 2023)."},{"page":50,"startToken":14972,"endToken":15316,"text":"47 \ncapacity market in which an Annual Capacity Auction is held approximately one month before \nthe relevant Capacity Commitment Period, effective March 31, 2026.108  In accepting ISO-\nNE’s proposal, the Commission expressly relied on its prior orders finding that MISO’s prompt \ncapacity auction schedule, under which MISO holds its auction two months before the delivery \nyear, is just and reasonable.109  The Commission has likewise accepted prompt auctions relying \non near-term procurement in NYISO.110  For the reasons discussed below, moving to a prompt \nschedule in PJM will provide the same substantial benefits, and particularly so in the dynamic \nand uncertain environment currently facing the PJM Region.  \ni. \nA prompt auction will significantly improve the accuracy of key BRA \nauction parameters, resulting in capacity prices that better reflect \nactual supply and demand fundamentals and system conditions in the \nDelivery Year. \nA prompt auction schedule will significantly enhance the accuracy of key BRA auction \nparameters, thereby resulting in capacity prices that better reflect actual market fundamentals \nand system conditions in the Delivery Year.  As Dr. Nicholson explains, a shorter forward \nperiod would reduce forecast uncertainty across each of the BRA’s key inputs.  Specifically, it \nwould allow PJM to forecast peak demand closer to the Delivery Year, reducing the risk of \nover-forecasting load and procuring more capacity than is actually needed, while also allowing \nPJM to base ELCC accreditation values on a resource mix and system conditions that are far \nmore likely to reflect what will actually exist during the Delivery Year rather than a three-and-\n \n108 See ISO-NE Order, at P 1.  \n109 Id., at P 32 (MISO Order, at PP 70-74 (finding that MISO’s prompt capacity auction market design may be \nbeneficial because “[load-serving entities] can accurately forecast their loads by taking into consideration changes \nsuch as those resulting from shifting economic conditions and MISO can accurately account for transmission \nconstraints, forced outage rates, and expected performance of Load Modifying Resources”); MISO Rehearing \nOrder, at PP 125-26).  \n110 See N.Y. Indep. Sys. Operator, Inc., 179 FERC ¶ 61,102, at PP 2-3 (2022)."},{"page":51,"startToken":15316,"endToken":15616,"text":"48 \na-half-year-old projection.111  It would also improve the accuracy of CETO/CETL values and \nthe resulting Local Deliverability Area Reliability Requirements, which likewise depend on \nassumptions about the future resource mix and transmission topology.112 \nThe net effect of this enhanced accuracy in BRA auction parameters is self-evident—\ncapacity prices that better reflect actual market fundamentals and system conditions.  The \nCommission has previously found this policy outcome to be just and reasonable.  Specifically, \nin accepting ISO-NE’s prompt auction schedule, the Commission found that the shorter \nforward period would “reduce demand uncertainty because the Installed Capacity Requirement \nwill be calculated using data that is closer in time to the Capacity Commitment Period” and \nwould “result in more accurate Qualified Capacity values for resource accreditation.”113  \nSimilarly, in the Commission’s order accepting MISO’s prompt auction schedule as just and \nreasonable, the Commission found that “MISO’s prompt Auction design allows load \nforecasting to occur within the year leading up to the Planning Year.”114  The Commission \nacknowledged the inherent benefits of this change, finding that “LSEs can accurately forecast \ntheir loads by taking into consideration changes such as those resulting from shifting economic \nconditions and MISO can accurately account for transmission constraints, forced outage rates, \nand expected performance of Load Modifying Resources.”115   \n \n111 Nicholson Affidavit, at ¶¶ 54-55. \n112 Id., at ¶ 56. \n113 ISO-NE Order, at P 32 (citing to ISO-NE Transmittal, at 23-30).  \n114 MISO Order, at PP 70-74 (finding that MISO’s prompt capacity auction market design may be beneficial \nbecause “[load-serving entities] can accurately forecast their loads by taking into consideration changes such as \nthose resulting from shifting economic conditions and MISO can accurately account for transmission constraints, \nforced outage rates, and expected performance of Load Modifying Resources”); MISO Rehearing Order, at PP \n125-26.  \n115 MISO Order, at PP 70-74."},{"page":52,"startToken":15616,"endToken":15905,"text":"49 \nThe same legal and policy rationale the Commission used in the ISO-NE Order and the \nMISO Order apply with equal if not greater force here.  The closer in time that PJM establishes \nits Installed Reserve Margin, ELCC accreditation values, CETO/CETL, and other key BRA \nauction parameters to the actual Delivery Year, the more those parameters will reflect the \nresource mix, load conditions, and system topology that actually exist, rather than a years-old \nprojection of what they might be.  These rationales are only strengthened by the rapidly \nchanging conditions currently facing the PJM Region; that is, the demands of large loads and \nassociated forecasting challenges, as well as the evolving resource mix and a shifting policy \nenvironment.   \nii. \nA prompt auction will significantly enhance the quality of information \nand the accuracy of the price signal used in generator Deactivation \ndecisions.  \nBy definition, a prompt auction schedule narrows the window across which resource \nowners must attempt to forecast future operational, environmental, regulatory, and market \nconditions when deciding whether and how to bid into a BRA and commit their Capacity \nResources for a Delivery Year.  As explained by Dr. Nicholson, this in turn enhances the \nquality and accuracy of the price signal that RPM sends to those resource owners in two distinct \nways.116   \nFirst, it increases the economic efficiency of resource exit from the market.  This \nenhanced efficiency in market exit will become increasingly important in the PJM Region in \nthe coming years, as a substantial volume of existing capacity in the PJM Region is expected \nto reach the end of its useful life and retire.117  Some aging capacity has been kept operational \n \n116 See Nicholson Affidavit, at ¶ 57. \n117 Id.; See also PJM White Paper, at 16."},{"page":53,"startToken":15905,"endToken":16276,"text":"50 \nin response to high prices.  Additional capacity has been kept operational by out-of-market \nmechanisms, such as RMR arrangements and FPA section 202c orders from the Department \nof Energy, but these interventions are, by definition, temporary and not designed as primary \ntools to achieve long-term resource adequacy.  Furthermore, as generating assets continue to \nage, keeping them operational will become prohibitively expensive, their operations will \nbecome even more challenging, and the resulting policy goal should be to manage their exit, \nnot keep them online indefinitely.  To this point, the Commission has previously found \nproposals that increase the efficiency of economic market entry and exit to be just and \nreasonable.118   \nSecond, a prompt auction allows resource owners that choose to remain in the market \nto “de-risk” their capacity supply offers by removing the need to price in the multi-year \n“operational and policy-uncertainty” premium described above in Section IV.A.iii.119  This \nshould apply downward pressure to capacity prices. \nIn short, the shift to a prompt structure will significantly enhance the quality of \ninformation and the accuracy of the investment signal used in resource owner market exit and \nDeactivation decisions.  Specifically, a prompt structure will allow commitment decisions to \nbe based on more current information, which will allow resource owners to better assess a \nCapacity Resource’s remaining economic life, operating condition, needed capital \n \n118  See e.g. Midcontinent Independent System Operator, Inc., 187 FERC ¶ 61,102, at P 80 (2024) (finding MISO’s \nRBDC proposal to adopt a sloped demand curve in the Auction to be just in reasonable in part because it will \nresult in capacity price signals that will “provide better incentives for efficient resource entry and exit,” among \nother reasons), modified on denial of reh’g by Midcontinent Independent System Operator, Inc., 189 FERC P \n61159 (2024); ISO New England, Inc., 173 FERC ¶ 61,161, at PP 48–50 (2020) (agreeing on rehearing that a \ncapacity market design “appropriately allows the [Forward Capacity Market] to provide the proper price signal \nto trigger entry and exit of capacity supply resources,” and finding that the Commission had properly “considered \n... whether the [Forward Capacity Market] provides the proper price signals to trigger appropriate entry and exit \nof capacity resources”).  \n119 Nicholson Affidavit, at ¶ 57."},{"page":54,"startToken":16276,"endToken":16577,"text":"51 \nimprovements, and market risks (e.g., Capacity Performance risk), producing in aggregate \noutcomes that better reflect the actual state of the PJM fleet as it ages, and capacity prices that \nmore accurately reflect the avoidable going forward costs of resources.   \niii. \nA prompt auction schedule will significantly enhance the quality of data \nused in PJM’s ELCC capacity accreditation, thereby better aligning \nboth price and payments with resource contributions to resource \nadequacy. \nAnother important benefit to a prompt auction schedule is the enhanced quality of the \ndata inputs used in PJM’s ELCC capacity accreditation process.  PJM’s capacity accreditation \nmethodology has grown substantially more complex and data-intensive since the Commission \nfirst approved the current multi-year forward period in 2006.  As noted above, in 2021 the \nCommission approved PJM’s transition from its longstanding eFORd methodology to an \nELCC approach.  In 2024 the Commission accepted PJM’s proposal to make further \nenhancements by transitioning to a “marginal” ELCC framework and extending ELCC \naccreditation to all Generation Capacity Resources.  In doing so, the Commission \nacknowledged a key underlying concern with ELCC in relation to the RPM’s three-year \nforward period—namely that “PJM’s RPM aims to ensure resource adequacy for a future \ndelivery year, and as such, there will inevitably be differences between the resource mix \nforecasted at the time of the auction and the actual, cleared resource mix.”120  Nonetheless, the \nCommission found that PJM had demonstrated that any differences between the forecasted and \ncleared resource mix are unlikely to introduce significant capacity accreditation errors.121  \nSpecifically, the Commission found that, based on PJM’s sensitivity analysis at the time, the \nforecast error was likely to be a “negligible amount” (an estimated 115 MW out of a 170,000 \n \n120PJM Interconnection, L.L.C., 186 FERC ¶ 61,080, at P 75 (2024).  \n121 Id., at P 76."},{"page":55,"startToken":16577,"endToken":16864,"text":"52 \nMW system).122  As discussed above in Section IV.A.iv, data over the last two years has \ndisproven this assumption.123   \nAdopting a prompt auction will significantly improve the quality of data used in PJM’s \nELCC modeling, thereby better addressing the Commission’s original concern in 2024 \nregarding the “differences between the resource mix forecasted at the time of the auction and \nthe actual, cleared resource mix.”124  As Dr. Nicholson explains, because a prompt auction \nwould base ELCC accreditation on a resource mix and system conditions far closer to the actual \nDelivery Year, this will lead to superior economic outcomes by reducing both over- and under-\naccreditation of resources and the resulting mispricing of capacity.125  Indeed, the Commission \nhas already found that a prompt auction schedule produces more accurate capacity \naccreditation values, including in the ISO-NE Order where the Commission found as just and \nreasonable a prompt auction schedule that would “result in more accurate Qualified Capacity \nvalues for resource accreditation.”126 \nFinally, a prompt auction schedule will allow Capacity Resources that have previously \nreceived a capacity commitment to have their accreditation values recalculated annually, using \nmore up-to-date data.  This provides several benefits, including ensuring that a resource’s \naccredited capacity value reflects the resource mix and system conditions that actually prevail \ncloser to the Delivery Year, rather than a three-and-a-half-year-old projection, giving resource \n \n122 Id.  \n123 See Nicholson Affidavit, at ¶¶ 44-50. \n124 See PJM Interconnection, L.L.C., 186 FERC ¶ 61,080 (2024) (approving PJM’s transition to a marginal ELCC \nframework and acknowledging that the resource mix forecasted at the time of the auction will inevitably differ \nfrom the actual, cleared resource mix).  \n125 Nicholson Affidavit, at ¶ 58. \n126 ISO-NE Order, at P 32."},{"page":56,"startToken":16864,"endToken":17144,"text":"53 \nowners better information with which to construct their capacity supply offers and plan \nmaintenance and retirement decisions, and reducing the risk that a resource is over- or under-\ncredited relative to its true reliability contribution. \niv. \nA prompt auction will significantly reduce the risks to new resources \nseeking to enter the market by creating more certainty regarding their \nexpected availability for the Delivery Year. \nA prompt auction will significantly reduce the risks, for customers and suppliers, \nassociated with the timing of new resources entering the market, as resources will have more \ncertainty about their expected availability for each Delivery Year, and particularly their first \nDelivery Year in service.  This will directly address the problem that the Commission has \npreviously described as “phantom entry,” where resources that receive a capacity commitment \nyears in advance are not actually operational in time for the delivery period.127  As the Filing \nParties explained in the ISO-NE proceeding, this phantom entry problem can raise capacity \nprices when the risk of non-commercial operation is priced into capacity offers.128 \nAs explained by Dr. Nicholson, to the extent that it exists in PJM, a prompt auction \nwould directly address the problem of “phantom entry” by allowing only those resources that \nhave actually achieved, or are on the imminent path to achieving, commercial operation to \nparticipate, rather than requiring new entrants to make a binding capacity commitment years \nbefore they can demonstrate they will actually be available.129  This will provide both PJM and \nMarket Participants with far greater certainty regarding actual resource availability for the \napplicable Delivery Year. \n \n127 See ISO-NE Order, at PP 13, 32. \n128 Id., at P 13.  \n129 Nicholson Affidavit, at ¶ 59."},{"page":57,"startToken":17144,"endToken":17388,"text":"54 \nV. \nREFUND EFFECTIVE DATE \nAs discussed above, Exelon respectfully requests that the Commission establish a \nrefund effective date of January 1, 2027, and permit Fast Track processing under Rule 206(h) \nto facilitate a Commission order by no later than January 31, 2027—currently the last day \nbefore the posting of the planning parameters for the 2030/31 Delivery Year BRA.   \nVI. \nRULE 206 REQUIREMENTS  \nTo the extent not already provided above, Exelon provides the following additional \ninformation required by Rule 206 of the Commission’s Rules of Practice and Procedure.130  \nExelon respectfully requests waiver of any part of the Commission’s regulations necessary to \nprocess this filing. \nA. \nGood faith estimate of financial impact or harm (Rule 206(b)(4)) \nThe complaint sets forth in detail above the financial impact and harm to PJM Market \nParticipants caused by the three-year forward period of RPM.   \nB. \nPractical, operational, or nonfinancial impacts (Rule 206(b)(5)) \nThe practical, operational, and nonfinancial impacts of the RPM’s three-year forward \nperiod are described at length in the sections above. \nC. \nWhether the matters are pending in any other FERC proceeding or other \nforum (Rule 206(b)(6)) \nThe issue of whether the three-year forward period of RPM has become unjust and \nunreasonable under FPA section 206, as presented in this complaint, is not to Exelon’s \nknowledge pending in any other existing Commission proceeding or forum in which Exelon is \na party. \n \n130 18 C.F.R. § 385.206."},{"page":58,"startToken":17388,"endToken":17641,"text":"55 \nD. \nSpecific relief or remedy requested (Rule 206(b)(7)) \nThe complaint sets forth in detail the specific relief requested. \nE. \nDocuments supporting the complaint (Rule 206(b)(8)) \nThis filing consists of the following: \n• This Transmittal Letter;  \n• Affidavit of Dr. Emma Nicholson, included as Attachment A;  \n• Affidavit of Deborah M. Sears, included as Attachment B; and \n• A Form of Notice, included as Attachment C. \nF. \nUse of alternative dispute resolution (Rule 206(b)(9)) \nExelon has not used the Enforcement Hotline, Dispute Resolution Service, tariff-based \ndispute resolution mechanisms, or other informal dispute resolution procedures, because the \ncomplaint argues that the three-year forward period of RPM is no longer just and reasonable, \nand is therefore unlawful under FPA section 206.  Only the Commission has the legal authority \nto provide the statutory remedy that the complaint requests.  For this reason, Exelon does not \nbelieve that alternative dispute resolution (“ADR”) under the Commission’s supervision could \nsuccessfully resolve the complaint, nor could any specific ADR procedures.  Exelon has not \nagreed to any process for resolving the complaint outside of the instant proceeding. \nG. \nNotice (Rule 206(b)(10))  \nExelon has appended a form of notice of this filing for publication in the Federal \nRegister, in accordance with the specifications in section 385.203(d) of the Commission’s \nrules.  \nH. \nRequest for Fast Track Processing (Rule 206(b)(11)) \nAs described above, Exelon respectfully requests that the Commission permit Fast \nTrack processing under Rule 206(h) to facilitate a Commission order by no later than January"},{"page":59,"startToken":17641,"endToken":17804,"text":"56 \n31, 2027—currently the last day before the posting of the planning parameters for the 2030/31 \nDelivery Year BRA.   \nVII. \nSERVICE AND NOTICE \nIn accordance with Rule 206(c), Exelon has served a copy of this complaint upon PJM, \nas Respondent, simultaneously with the filing of the complaint. \nVIII. CONCLUSION \nWherefore, for the foregoing reasons, Exelon respectfully requests that the \nCommission: (i) find under FPA section 206 that the current three-year forward period of \nPJM’s RPM is no longer just and reasonable; (ii) adopt as a replacement rate a “prompt” \nauction schedule, to run two months before a given Delivery Year, starting with the 2030/2031 \nDelivery Year and continuing beyond; (iii) establish a refund effective date of January 1, 2027; \nand (iv) permit Fast Track processing under Rule 206(h) to facilitate a Commission order by \nno later than January 31, 2027—currently the last day before the posting of the planning \nparameters for the 2030/31 Delivery Year BRA."},{"page":60,"startToken":17804,"endToken":17901,"text":"57 \nRespectfully submitted, \n/s/ Jordan Kwok \n/s/ Thomas S. DeVita \nJordan Kwok \nThomas S. DeVita \nDirector, Federal Regulatory Affairs \nKimberly B. Frank \nExelon Corporation \nStuart B. Robbins \n701 Ninth Street, N.W. \nK&L Gates LLP \nWashington, D.C. 20068 \n1601 K Street, NW \n(667) 313-0421 \nWashington, DC  20006 \njordan.kwok@exeloncorp.com \n(202) 778-9000 \n \nthomas.devita@klgates.com \n/s/ Alejandro Bautista \nkimberly.frank@klgates.com \nAlejandro Bautista \nstuart.robbins@klgates.com \nAssistant General Counsel \n \nExelon Corporation \nCounsel for Exelon Corporation  \n2301 Market Street \n \nPhiladelphia, PA 19101 \n \n(267) 533-0120 \n \nalejandro.bautista@exeloncorp.com \n \n \n \n \nDated: November 3, 2026"},{"page":61,"startToken":17901,"endToken":18031,"text":"58 \nCERTIFICATE OF SERVICE \nI hereby certify that I have on this date caused a copy of the foregoing document to be \nserved upon PJM Interconnection, L.L.C., at the following addresses obtained from the \nCommission’s list of corporate officials designated to receive services pursuant to 18 C.F.R. § \n385.2010(k):  \nJessica M. Lynch \nAssociate General Counsel \nPJM Interconnection, L.L.C. \n2750 Monroe Blvd. \nAudubon, PA 19403 \n(267) 563-3688 \nFERCeService@pjm.com  \nMark J. Stanisz \nAssociate General Counsel \nPJM Interconnection, L.L.C. \n2750 Monroe Blvd. \nAudubon, PA 19403 \n(610) 666-4707 \nFERCeService@pjm.com   \n \nDated: November 3, 2026 \n \n/s/ Stuart B. Robbins  \nStuart B. Robbins  \nK&L Gates LLP \n1601 K Street, NW \nWashington, DC  20006 \n(202) 778-9148 \nstuart.robbins@klgates.com  \n \nCounsel for Exelon Corporation"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":0,"startToken":0,"endToken":126},{"p":2,"at":0,"title":"Table of Contents","method":"printed heading","endPage":2,"endAt":830,"startToken":126,"endToken":156},{"p":2,"at":830,"title":"A. The Current Three-Year Forward Period of RPM is No Longer Just and","method":"printed heading","endPage":2,"endAt":2835,"startToken":156,"endToken":377},{"p":2,"at":2835,"title":"B. The Commission Should Adopt a Prompt Auction Schedule as the Just and","method":"printed heading","endPage":3,"endAt":1320,"startToken":377,"endToken":550},{"p":3,"at":1320,"title":"C. Whether the matters are pending in any other FERC proceeding or other","method":"printed heading","endPage":6,"endAt":905,"startToken":550,"endToken":1392},{"p":6,"at":905,"title":"I. INTRODUCTION","method":"PDF bookmark","endPage":6,"endAt":909,"startToken":1392,"endToken":1393},{"p":6,"at":909,"title":"INTRODUCTION","method":"printed heading","endPage":13,"endAt":788,"startToken":1393,"endToken":3970},{"p":13,"at":788,"title":"II. PARTIES AND COMMUNICATIONS","method":"PDF bookmark","endPage":13,"endAt":821,"startToken":3970,"endToken":3974},{"p":13,"at":821,"title":"A. Complainant Exelon","method":"PDF bookmark","endPage":14,"endAt":4,"startToken":3974,"endToken":4109},{"p":14,"at":4,"title":"B. Respondent PJM","method":"PDF bookmark","endPage":14,"endAt":674,"startToken":4109,"endToken":4207},{"p":14,"at":674,"title":"C. Communications","method":"PDF bookmark","endPage":15,"endAt":4,"startToken":4207,"endToken":4375},{"p":15,"at":4,"title":"III. Background","method":"PDF bookmark","endPage":15,"endAt":10,"startToken":4375,"endToken":4376},{"p":15,"at":10,"title":"BACKGROUND","method":"printed heading","endPage":17,"endAt":138,"startToken":4376,"endToken":4977},{"p":17,"at":138,"title":"IV. LEGAL ARGUMENT","method":"PDF bookmark","endPage":17,"endAt":159,"startToken":4977,"endToken":4980},{"p":17,"at":159,"title":"A. The Current Three-Year Forward Period of RPM is No Longer Just and Reasonable.","method":"PDF bookmark","endPage":17,"endAt":245,"startToken":4980,"endToken":4994},{"p":17,"at":245,"title":"i. The risk balancing analysis the Commission relied on in 2006 to accept the load forecast inaccuracies inherent in RPM’s multi-year forward period has fundamentally collapsed in 2026.","method":"PDF bookmark","endPage":19,"endAt":344,"startToken":4994,"endToken":5634},{"p":19,"at":344,"title":"a. Evidence that PJM Load Forecast Inaccuracies Have Increased Since 2006.","method":"PDF bookmark","endPage":24,"endAt":642,"startToken":5634,"endToken":7252},{"p":24,"at":642,"title":"b. Evidence that Capacity Resources cannot be constructed in the PJM Region within the current three-year cycle.","method":"PDF bookmark","endPage":28,"endAt":719,"startToken":7252,"endToken":8417},{"p":28,"at":719,"title":"ii. The prospective assumptions in 2006 regarding the ability of RPM’s multi-year forward period to incentivize LSE bilateral contracting and risk hedging have been disproven over the course of 20 years.","method":"PDF bookmark","endPage":33,"endAt":1155,"startToken":8417,"endToken":10103},{"p":33,"at":1155,"title":"iii. The current three-year forward period inhibits efficient resource exit and Deactivation, as it requires generation owners to invest in the absence of reasonable predictability in future operational capability and environmental policy.","method":"PDF bookmark","endPage":35,"endAt":820,"startToken":10103,"endToken":10653},{"p":35,"at":820,"title":"a. Operational Uncertainties","method":"PDF bookmark","endPage":36,"endAt":1533,"startToken":10653,"endToken":11056},{"p":36,"at":1533,"title":"b. Environmental Policy Uncertainties","method":"PDF bookmark","endPage":43,"endAt":477,"startToken":11056,"endToken":13053},{"p":43,"at":477,"title":"iv. PJM’s current capacity accreditation methodology (ELCC) bears no resemblance to the eFORd model considered by the Commission in 2006, and the three-year forward period forces PJM to integrate speculative assumptions into its ELCC modeling.","method":"PDF bookmark","endPage":47,"endAt":657,"startToken":13053,"endToken":14172},{"p":47,"at":657,"title":"v. The current three-year forward period undermines the accuracy of other BRA planning parameters, including the assumed resource mix in each Locational Deliverability Area used to calculate CETO/CETL values, leading to unjust and unreasonable results.","method":"PDF bookmark","endPage":49,"endAt":771,"startToken":14172,"endToken":14788},{"p":49,"at":771,"title":"B. The Commission Should Adopt a Prompt Auction Schedule as the Just and Reasonable Replacement Rate.","method":"PDF bookmark","endPage":50,"endAt":719,"startToken":14788,"endToken":15080},{"p":50,"at":719,"title":"i. A prompt auction will significantly improve the accuracy of key BRA auction parameters, resulting in capacity prices that better reflect actual supply and demand fundamentals and system conditions in the Delivery Year.","method":"PDF bookmark","endPage":52,"endAt":757,"startToken":15080,"endToken":15734},{"p":52,"at":757,"title":"ii. A prompt auction will significantly enhance the quality of information and the accuracy of the price signal used in generator Deactivation decisions.","method":"PDF bookmark","endPage":54,"endAt":270,"startToken":15734,"endToken":16317},{"p":54,"at":270,"title":"iii. A prompt auction schedule will significantly enhance the quality of data used in PJM’s ELCC capacity accreditation, thereby better aligning both price and payments with resource contributions to resource adequacy.","method":"PDF bookmark","endPage":56,"endAt":245,"startToken":16317,"endToken":16900},{"p":56,"at":245,"title":"iv. A prompt auction will significantly reduce the risks to new resources seeking to enter the market by creating more certainty regarding their expected availability for the Delivery Year.","method":"PDF bookmark","endPage":57,"endAt":4,"startToken":16900,"endToken":17145},{"p":57,"at":4,"title":"V. REFUND Effective date","method":"PDF bookmark","endPage":57,"endAt":382,"startToken":17145,"endToken":17206},{"p":57,"at":382,"title":"VI. Rule 206 REQUIREMENTS","method":"PDF bookmark","endPage":57,"endAt":702,"startToken":17206,"endToken":17252},{"p":57,"at":702,"title":"A. Good faith estimate of financial impact or harm (Rule 206(b)(4))","method":"PDF bookmark","endPage":57,"endAt":922,"startToken":17252,"endToken":17289},{"p":57,"at":922,"title":"B. Practical, operational, or nonfinancial impacts (Rule 206(b)(5))","method":"PDF bookmark","endPage":57,"endAt":1133,"startToken":17289,"endToken":17319},{"p":57,"at":1133,"title":"C. 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