{"document":{"slug":"order-er26-3380-pjm-backstop","title":"Order accepting PJM's Reliability Backstop Procurement, suspending it to February 28, 2027, and establishing further procedures","issued":"2026-09-29","accession":"20260929-3099","docket":"ER26-3380-000","group":"PJM Reliability Backstop Procurement","filer":"FERC","kind":"order","file":"sources/originals/20260929-3099_order.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20260929-3099","sha256":"3efe24a0a8d45db5251b8fdec097c495e5acaa37e12e882751b39056d9d1cb47","pages":97,"tokens":37818,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":291,"text":"196 FERC ¶ 61,245 \nUNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \nBefore Commissioners: Laura V. Swett, Chairman; \n David Rosner, Lindsay S. See, \n Judy W. Chang, and David LaCerte. \nPJM Interconnection, L.L.C. \nDocket Nos. ER26-3380-000 \nEL26-108-000\nORDER ACCEPTING RELIABILITY BACKSTOP PROCUREMENT AND \nESTABLISHING FURTHER PROCEDURES \n(Issued September 29, 2026) \nOn July 31, 2026, as supplemented on August 14, 2026, PJM submitted proposed \nchanges to its Open Access Transmission Tariff (OATT or Tariff) and Reliability \nAssurance Agreement (RAA),1 pursuant to section 205 of the Federal Power Act (FPA),2\nto establish the Reliability Backstop Procurement (RBP). The RBP is a one-time \nprocurement of new capacity to address significant resource adequacy challenges \nprimarily driven by an influx of large loads.3 As discussed below, we accept the \nproposed RBP for filing, suspend it for five months, effective February 28, 2027, \nsubject to refund, and establish a paper hearing. We also establish an FPA section 206 \nproceeding.4\nWe find that certain aspects of PJM’s proposal are just and reasonable. With \nrespect to other aspects of PJM’s proposal that may be unjust and unreasonable, we direct \nfurther briefing regarding potential alternative approaches that the Commission believes \n1 Capitalized terms that are not defined in this order have the meaning specified in \nthe OATT and RAA. \n2 16 U.S.C. § 824d. \n3 PJM’s proposed rules governing the RBP are primarily set forth in proposed \nTariff, Attachment DD, section 18, with additional conforming revisions and new \nprovisions in other sections of: (1) Attachment DD; (2) RAA, Article 7, sections 7.2B \nand 7.2C; (3) RAA, Schedule 8.1.D; and (4) Tariff, Definitions. See Appendix A for \ntariff records accepted and suspended in this order. \n4 16 U.S.C. § 824e."},{"page":2,"startToken":291,"endToken":615,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 2 - \nmay be just and reasonable. We therefore establish paper hearing procedures and a \nprocess by which the Commission may potentially revise those provisions consistent with \nFPA section 206. \nRecognizing the looming capacity shortfall facing PJM, we encourage PJM to \nconsider the issues we raise in this order and determine the most expeditious path to \nresolving them. In particular, we encourage PJM to swiftly submit a new FPA section 205 \nfiling without delay. That new filing may in turn obviate the need for the paper hearing \nprocedures that we establish here and could expedite a potential RBP auction. \nI.\nBackground \nPJM conducts a Base Residual Auction (BRA) to procure resource commitments \nsufficient to meet reliability requirements in the PJM region for a given delivery year, \nwhich spans from June 1 to May 31.5 The BRA and three Incremental Auctions are the \nReliability Pricing Model (RPM) Auctions for a given delivery year. \nIn December 2025, PJM announced that a BRA had cleared significantly below \nPJM’s reliability requirement for the first time in the auction’s history. The 2027/2028 \nBRA cleared 6,623 MW6 short of the reliability requirement, when also accounting for \nFixed Resource Requirement (FRR) resources.7 The largest driver of the shortfall was \n5,250 MW of load growth forecast for that delivery year, nearly 5,100 MW of which was \n5 PJM, Intra-PJM Tariffs, OATT, attach. DD, § 5.4 (Reliability Pricing Model \nAuctions) (10.0.0), § 5.4(a). \n6 All supplier MW values in this order are expressed in unforced capacity (UCAP). \n7 Both the BRA and the FRR Alternative are designed to secure enough power \nsupply to ensure that sufficient capacity will be available to meet peak customer demand. \nThe FRR Alternative allows Load-Serving Entities (LSE) to elect to meet their resource \nadequacy needs with their own resources. See RAA SCHEDULE 8.1.D, RAA \nSCHEDULE 8.1.D-FRR Capacity Plans (14.2.0)."},{"page":3,"startToken":615,"endToken":1018,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 3 - \ndue to data centers.8 The 2027/2028 BRA, which cleared at the temporary price cap of \n$333.44/MW-day, was the third BRA in a row to clear at historically high prices.9\nIn January 2026, the White House National Energy Dominance Council (NEDC) \nand the governors of all 13 PJM states released a document titled “Statement of \nPrinciples Regarding PJM” (NEDC/PJM Governors’ Principles).10 The document urged \nPJM to file tariff revisions with the Commission to “[p]rovide 15-year price certainty for \nnew capacity resources,” which “can be accomplished by holding a Reliability Backstop \nAuction to procure new capacity resources commencing no later than September 2026.” \nNoting the unique risks data centers pose to resource adequacy, the document urged PJM \nto allocate the costs of any new capacity procured to load-serving entities with data \ncenters that have not self-procured new capacity or agreed to be curtailable, with any \nremaining costs allocated to load-serving entities based on their remaining net-short \npositions. \nAlso in January 2026, the PJM Board announced its decision on a Critical Issue \nFast Path (CIFP) process addressing large load issues in PJM, which, among other things, \nincluded accelerating a backstop capacity procurement.11\n8 PJM Inside Lines, “PJM Auction Procures 134,479 MW of Generation \nResources,” (Dec. 17, 2025) https://insidelines.pjm.com/pjm-auction-procures-134479-\nmw-of-generation-resources/. In PJM’s 2026 load forecast released in January, PJM cut its \npeak demand forecasts for summer 2027 and summer 2028 by 4,000 MW and 4,400 MW, \nrespectively, citing tighter vetting of Load Adjustment requests and revised electric vehicle \nand economic assumptions. PJM, 2026 PJM Load Forecast Report 4-5 (Jan. 2026), \nhttps://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2026-load-\nreport.pdf. \n9 While clearing at historically high prices, these previous two BRAs did not clear \nsignificantly below PJM’s reliability requirement. See PJM, 2025/2026 Base Residual \nAuction Report (July 30, 2024), https://www.pjm.com/-/media/DotCom/markets-\nops/rpm/rpm-auction-info/2025-2026/2025-2026-base-residual-auction-report.pdf; PJM, \n2026/2027 Base Residual Auction Report (July 22, 2025), https://www.pjm.com/-\n/media/DotCom/markets-ops/rpm/rpm-auction-info/2026-2027/2026-2027-bra-report.pdf. \n10 U.S. Department of Energy, Statement of Principles Regarding PJM (Jan. 2026), \nhttps://www.energy.gov/documents/statement-principles-regarding-pjm. \n11 PJM, Board Decisional Letter on Critical Issue Fast Path - Large Load \nAdditions (Jan. 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-\nare/public-disclosures/2026/20260116-pjm-board-letter-re-results-of-the-cifp-process-\nlarge-load-additions.pdf."},{"page":4,"startToken":1018,"endToken":1387,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 4 - \nIn March 2026, the White House released the Ratepayer Protection Pledge to \nassure that new large loads will, at a minimum, “build, bring, or buy the new generation \nresources and electricity needed to satisfy their new energy demands, paying the full cost \nof those resources.”12 Many utilities, cooperatives, data center developers, and governors \nhave signed the pledge. \nIn April 2026, the PJM Board issued a letter initiating a targeted CIFP process \nto engage stakeholders in the development of the RBP.13 Soon after, PJM proposed a \ntwo-path mechanism for the RBP: a central procurement path (i.e., the RBP auction of \nthe instant filing) and a facilitated bilateral contracting matchmaking path that PJM states \nrequires no filing with the Commission.14 PJM plans to run this latter path in parallel \nwith the RBP auction to streamline direct contracting between supply and demand. \nAccording to the PJM Board, bilateral contracting is “highly preferred among \nmembers.”15\nIn June 2026, PJM issued a bilateral matchmaking request for proposals, with \nresponses due July 21, 2026, at which time consultant Charles River Associates \ncommenced the bilateral matchmaking process.16 This process is intended to be iterative \nand will continue for six to nine months. Supply-side resources in the bilateral matching \n12 The White House, President Trump’s Ratepayer Protection Pledge Secures \nAmerican AI Dominance, Protects Consumers (July 2026), \nhttps://www.whitehouse.gov/releases/2026/07/president-trumps-ratepayer-protection-\npledge-secures-american-ai-dominance-protects-consumers/ (identifying 282 utilities, \ncooperatives, and data center developers and 23 governors that have joined the Ratepayer \nProtection Pledge). \n13 PJM, Critical Issue Fast Path (CIFP) (Apr. 2026), https://www.pjm.com/-\n/media/DotCom/about-pjm/who-we-are/public-disclosures/2026/20260408-cifp-rbp-\ninitiation-letter.pdf. \n14 Transmittal at 30. \n15 PJM, CIFP Reliability Backstop Procurement – PJM Board Decision 1 \n(July 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-\ndisclosures/2026/20260727-cifp-reliability-backstop-procurement-pjm-board-\ndecision.pdf. See also Transmittal at 30 (“Throughout the underlying stakeholder \nprocess, PJM members have expressed a strong preference for bringing new capacity to \nthe PJM system voluntarily through bilateral contracting rather than through the RBP.”). \n16 Charles River Associates, PJM Reliability Backstop Procurement \nBilateral Request for Proposal (RFP) (June 2026), https://www.pjm.com/-\n/media/DotCom/committees-groups/cifp-rbp/postings/pjm-bilateral-rfp-document.pdf."},{"page":5,"startToken":1387,"endToken":1792,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 5 - \nprocess that do not form agreements may bid into the RBP auction. Bidders will not \nbe permitted to then exit the RBP auction process to enter bilateral arrangements, but \nsupply-side resources that are not selected in the RBP auction may re-engage in bilateral \nmatching. \nOn May 27, 2026, PJM announced the results of an April survey to gauge interest \nfrom load in the RBP.17 PJM states that the response revealed substantial large load \ninterest from 21 entities representing 47 potential large load projects in the PJM Region; \nthose projects average 850 MW each, with a median size of 300 MW. PJM explains that \nthe supply-side response was also significant, with 397 potential supply-side projects by \n87 entities and approximately 136 GW in total potential capacity. Of the supply-side \nprojects, 72% indicated a readiness to engage with their large load counterparts \nimmediately, while 91% of the large load projects indicated the same. \nOn June 30, 2026, the Members Committee voted on 13 RBP auction proposals as \nan advisory to the PJM Board.18 Stakeholders endorsed only one proposal, meaning that \nit received at least two-thirds sector-weighted support. That support (75%) went to a \nproposal sponsored by the Data Center Coalition (DCC) and a coalition of Electric \nDistributors.19 PJM’s own proposal received only 30% support.20 The DCC/Electric \nDistributors coalition proposed a “subscription model” in which large loads wishing to \nparticipate would provide their LSE with a MW volume for PJM to purchase on their \nbehalf. PJM instead proposed to base its procurement target on the shortage in the \n2028/2029 BRA and to allocate costs to Electric Distributor zone/areas pro rata based \non forecasted load adjustments. In addition, the DCC/Electric Distributors coalition’s \nproposal included a locational constraint that allowed only 500 MW to serve the \nMid-Atlantic Dominion reserve sub-zone, which was intended to prevent future \n17 Transmittal at 18 (citing Charles River Associates, PJM Reliability Backstop \nRFI Summary (May 2026), https://www.pjm.com/-/media/DotCom/committees-\ngroups/cifp-rbp/2026/20260527/20260527-informational-only---reliability-backstop-rfi-\nsummary---charles-river-associates.pdf (Charles River Associates Survey Results)). \n18 Id. at 20. \n19 PJM Members Committee, Supplemental Voting Results (June 2026), \nhttps://www.pjm.com/-/media/DotCom/committees-\ngroups/committees/mc/2026/20260630-special/mc-voting-results---agenda-item-3o---\njoint-edcs-and-data-center-coalition-rbp-proposal.pdf. \n20 PJM Members Committee, Supplemental Voting Results (June 2026), \nhttps://www.pjm.com/-/media/DotCom/committees-\ngroups/committees/mc/2026/20260630-special/mc-voting-results---agenda-item-3l---\npjm-rbp-proposal.pdf."},{"page":6,"startToken":1792,"endToken":2153,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 6 - \nBRA price separation due to RBP resources being electrically separated from data \ncenters. PJM’s proposal had no locational constraints. Despite these differences, \nmany of the core components of the two proposals were the same, including resource \ncommitments up to the 2042/2043 delivery year, requiring a resource in-service date \nby the 2032/2033 delivery year, a must-offer RPM requirement with contracts for \ndifferences, and similar new supply qualifications, shortfall penalties, and supplier \ncollateral requirements. \nOn July 14, 2026, PJM announced that the 2028/2029 BRA cleared short of the \nPJM Region’s reliability requirement (when also accounting for FRR resources) at a \nclearing price at the temporary price cap of $325/MW-day.21\nOn July 27, 2026, the PJM Board announced that it had adopted PJM’s proposal \nwith three “targeted changes” to adopt certain concepts that had roots in the DCC/Electric \nDistributors coalition’s proposal.22 First, the PJM Board added two RBP opt-outs: one \nthat applies to qualifying cooperatives and municipal utilities, and one that applies to \nElectric Distributor zone/areas that are addressing their capacity needs through state peak \nshaving adjustment programs. Second, the PJM Board proposed to cap the MW-weighted \naverage cost of accepted supply offers at $555/MW-day. Third, the PJM Board added \nstringent LSE collateral requirements to address potential defaults on the demand side. \nThe PJM Board explained that it did not adopt the DCC/Electric Distributors coalition’s \nentire proposal because a voluntary subscription framework would not provide sufficient \nassurance that the RBP would procure enough capacity.23\n21 PJM Inside Lines, “PJM Capacity Auction Procures 138,318 MW of \nGeneration Resources as Work Continues to Address Growing Electricity Demand,” \nhttps://insidelines.pjm.com/pjm-capacity-auction-procures-138318-mw-of-generation-\nresources-as-work-continues-to-address-growing-electricity-demand/. \n22 PJM, CIFP Reliability Backstop Procurement – PJM Board Decision\n(July 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-\ndisclosures/2026/20260727-cifp-reliability-backstop-procurement-pjm-board-\ndecision.pdf (“targeted changes” highlighted in blue). See Transmittal at 22. \n23 Paula Conboy, Chair, PJM Board of Managers, Board Decisional Letter on \nCritical Issue Fast Path – Reliability Backstop Procurement and Connect and Manage, \nat 1 (July 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-\ndisclosures/2026/20260727-board-decisional-letter-on-cifp-reliability-backstop-\nprocurement-and-connect-and-manage.pdf."},{"page":7,"startToken":2153,"endToken":2598,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 7 - \nII.\nFiling \nOn July 31, 2026, PJM submitted revisions to the Tariff and RAA to establish the \nRBP, a one-time procurement of new capacity to address resource adequacy challenges \nprimarily driven by an influx of large loads. According to PJM, the goal of the RBP is \nto obtain commitments of new RBP UCAP MW24 from eligible new resources, called \nRBP Resources, for a fixed term of up to 15 years, starting with the 2028/2029 delivery \nyear at the earliest and ending no later than the 2042/2043 delivery year.25 PJM states \nthat committing supply for terms of up to 15 years creates revenue certainty for the \nsupply resources, generally can reduce financial and development risk, and may improve \nfinancing opportunities through lower capital costs or more favorable financing terms.26\nParticipants in the RBP are: (1) sellers with RBP Sell Offers submitted on \nbehalf of RBP Resources; and (2) PJMSettlement, Inc., acting as a counterparty on behalf \nof buyers, i.e., LSEs.27 PJM states that the RBP aims to procure capacity equal to the \n6,831 MW shortfall in the 2028/2029 BRA (Initial RBP Target), adjusted downward to \nreflect qualifying new capacity (Qualifying RBP Offset UCAP MW) serving new load \nand certain qualifying Electric Distributors that elect and meet requirements to opt out of \nthe RBP (Opt-Out UCAP MW). The Final RBP Target is the Initial RBP Target after \ndownward adjustments. Pursuant to the proposed Tariff provisions, new load is load that \nhas an executed electric service agreement or transmission service agreement indicating \nthat the load will come online during the 2027/2028 or 2028/2029 delivery year.28\nTo avoid double procurement, PJM proposes to require all available committed \nRBP UCAP MW to offer into the RPM Auctions as a price-taker, i.e., $0/MW-day \nUCAP, beginning with the first RPM Auction following the RBP commitment, for the \napplicable offered delivery year in which the term of the committed RBP UCAP MW \n24 PJM’s filing includes several newly defined terms. See PJM, Intra-PJM Tariffs, \nC-D, OATT Definitions – C-D (47.0.0); id., E-F, OATT Definitions - E - F (45.0.0); id., \nO-P-Q, OATT Definitions - O - P - Q (39.0.0); id., R-S, OATT Definitions – R - S \n(47.0.0). \n25 Transmittal at 8-9. \n26 Id. at 63-64. \n27 PJMSettlement, a non-profit subsidiary of PJM, handles credit, billing, \nand settlement functions for PJM and acts as a counterparty to PJM members’ pool \ntransactions in the PJM markets on behalf of the ultimate buyer of the product. \nTransmittal at 47. \n28 Transmittal at 35; Proposed Tariff, attach. DD, § 18.2 (0.0.0), § 18.2(c)."},{"page":8,"startToken":2598,"endToken":3024,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 8 - \nbegins and continuing each subsequent delivery year through the end of the fixed term. \nAll RBP Resources clearing in the RPM are paid RPM Auction Credits in accordance \nwith RPM rules and are then settled based on a contract-for-difference design for the \nRBP UCAP MW. All load that is allocated RBP Charges and participates in the RPM \nis charged or receives RBP Charges, based on the contract-for-difference settlement. \nRBP Credits and Charges are only assessed to the extent that RBP UCAP MW are \ncommitted in the RPM and physically available for dispatch in the relevant delivery year. \nPJM states that if the Commission accepts its filing without significant revisions, \nPJM commits to opening the RBP bid submission window on September 30, 2026, and \nclosing it three weeks later on October 21, 2026.29 PJM states that a clearing and \nselection process would follow and conclude six weeks after the closing of the offer \nsubmission window. PJM states that it would announce the pay-as-bid results to sellers a \nfew days before the 2029/2030 BRA opens on December 9, 2026.30 PJM also commits to \npost publicly the aggregate MW procured and a MW-weighted average of the cost.31\nPJM states that “to facilitate Commission approval and prompt opening of the \nRBP procurement window, PJM consents to the Commission’s exercise of authority to \nmodify and/or sever the proposed Tariff and RAA language, as needed and permitted \nunder section 205 of the FPA and NRG Power Marketing, LLC v. FERC, where such \nmodification and/or severance is consistent with PJM’s overarching objectives in this \nfiling,” and asks only that the Commission “expressly prescribe the revised rate or rule in \nits order.”32\nIII.\nNotice of Filing and Responsive Pleadings \nNotice of PJM’s filing was published in the Federal Register, 91 Fed. Reg. 50826 \n(Aug. 6, 2026), with interventions and protests due on or before August 21, 2026. \nNotices of intervention and timely-filed motions to intervene were submitted by the \nentities listed in Appendix B to this order.33 Comments and protests were submitted by \nnumerous entities, as summarized below. Answers were submitted by AEP, the \n29 Transmittal at 3 n.5, 48; Proposed Tariff, attach. DD, § 18.4 (0.0.0). \n30 Transmittal at 133. \n31 Id. at 79. \n32 Id. at 3, 130-31. See NRG Power Mktg., LLC v. FERC, 862 F.3d 108 \n(D.C. Cir. 2017) (NRG). \n33 The abbreviated names or acronyms by which these entities are referred to in \nthis order are noted in Appendix B."},{"page":9,"startToken":3024,"endToken":3479,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 9 - \nKentucky Attorney General, EKPC, the Market Monitor, NJBPU, NOVEC, Voltus, PJM, \nP3, PPL, Constellation, Indicated PJM TOs, and FirstEnergy. Additional answers were \nsubmitted by Constellation and EKPC. \nIV.\nDiscussion \nA.\nProcedural Matters \nPursuant to Rule 214 of the Commission’s Rules of Practice and Procedure, \n18 C.F.R. § 385.214 (2025), the notices of intervention and timely, unopposed motions \nto intervene serve to make the entities that filed them parties to this proceeding. \nRule 213(a)(2) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. \n§ 385.213(a)(2) (2025), prohibits an answer to a protest or answer unless otherwise \nordered by the decisional authority. We accept the answers filed by AEP, the Kentucky \nAttorney General, EKPC, the Market Monitor, NJBPU, NOVEC, Voltus, PJM, P3, \nConstellation, PPL, Indicated PJM TOs, and FirstEnergy because they have provided \ninformation that assisted us in our decision-making process. \nB.\nSubstantive Matters \nOur preliminary analysis indicates that, while some aspects of PJM’s proposal are \njust and reasonable, other aspects of PJM’s proposal have not been shown to be just and \nreasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or \notherwise unlawful. PJM’s filing raises issues of material fact that cannot be resolved \nbased on the record before us and that are more appropriately addressed in the paper \nhearing procedures established below. Accordingly, we accept PJM’s proposal for filing \nand suspend it for five months to become effective February 28, 2027, subject to refund \nand to the outcome of paper hearing procedures. Specifically, the paper hearing \nprocedures should address the Commission’s potential modifications with respect to the \nportions of PJM’s existing RBP proposal that are discussed immediately below. Aside \nfrom the three issues discussed directly below, we find that the other aspects of PJM’s \nRBP proposal are just and reasonable, as discussed in this order. \nWe direct PJM to submit an initial brief addressing the paper hearing topics \ndiscussed below (cost allocation, Transmission Owner exit rules, and LSE collateral \nrequirements), and to discuss in that brief whether its proposal could be just and \nreasonable if modified. Other parties to this proceeding may also submit initial briefs \non these topics. Initial briefs are due 45 days from the date of this order. However, \nwe anticipate that the Commission would grant a motion to hold that briefing in this \nproceeding in abeyance if PJM submitted a new section 205 filing within 30 days from \nthe date of this order. Absent any such abeyance, responses to those initial briefs are due \n20 days after the date that initial briefs are due. No additional answers or briefs will be \npermitted, and the Commission will look with great disfavor on any requests to extend"},{"page":10,"startToken":3479,"endToken":3931,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 10 - \nthese deadlines. Any evidence included with the briefs shall be submitted in the form \nof affidavits accompanying the briefs. We remind parties that their pleadings in Docket \nNo. ER26-3380-000 remain part of the record in this proceeding and that they need not—\nand should not—repeat their prior arguments in the paper hearing. \nWe anticipate that, following the paper hearing, the Commission may need to \ndirect significant modifications to certain aspects of PJM’s proposal pursuant to its \nauthority under section 205(e) of the FPA34 and Western Resources, Inc. v. FERC.35\nPursuant to Western Resources, the Commission may “transform” an existing \nFPA section 205 proceeding into an FPA section 206 proceeding and “impose its own \nrate,” provided the Commission makes three requisite findings: (1) that the utility has \nfailed to show that the proposed rate is just and reasonable, (2) that the existing rate is no \nlonger just and reasonable, and (3) that the substitute rate established by the Commission \nis just and reasonable.36 We anticipate that, based on the record developed through the \npaper hearing, the Commission may find that each of these three prongs is satisfied and \nimpose a new rate that incorporates some of the potential modifications discussed below. \nWe first discuss why PJM’s existing rate may be unjust and unreasonable, then turn to \nwhy each aspect of PJM’s proposal that we are setting for paper hearing may be unjust \nand unreasonable, and then discuss why PJM’s proposal may be just and reasonable if \nmodified. \nIn addition to establishing paper hearing procedures under FPA section 205, \nthis order also establishes a new FPA section 206 proceeding in anticipation of the \nCommission directing significant modifications to certain aspects of PJM’s RBP \nproposal following the paper hearing. We institute this FPA section 206 proceeding \nbecause, as discussed in the next section below, PJM’s existing Tariff may be unjust and \nunreasonable. When the Commission directs modifications under Western Resources, \nit does so by “transform[ing]” an existing section 205 proceeding into a section 206 \nproceeding and making the requisite findings. Though we are establishing an FPA \nsection 206 proceeding today (Docket No. EL26-108), we are not instituting any further \nprocess under FPA section 206 at this time. \n34 16 U.S.C. § 824d (“[T]he Commission may make such orders with reference \nthereto as would be proper in a proceeding initiated after it had become effective.”). \n35 9 F.3d 1568 (D.C. Cir. 1993) (Western Resources). See Tenn. Gas Pipeline Co. \nv. FERC, 860 F.2d 446, 453-54 (D.C. Cir. 1988) (interpreting similar statutory language \nin section 4(e) of the Natural Gas Act).\n36 Western Resources, 9 F.3d at 1579."},{"page":11,"startToken":3931,"endToken":4335,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 11 - \nWhile the Commission is establishing the procedures described above, we strongly \nencourage PJM to address the issues discussed in this order by submitting an alternative \nproposal pursuant to its FPA section 205 filing rights without delay. Such a filing could \nexpedite the resolution of the concerns that we have identified with certain aspects of \nPJM’s RBP proposal. Should PJM submit a filing under FPA section 205, it should \nexplain how its proposal resolves the concerns discussed in this order.37\n1.\nPJM’s Existing Tariff May Be Unjust and Unreasonable \nWe preliminarily find that PJM’s existing Tariff may be unjust and unreasonable \nbecause the existing reliability backstop provisions appear to be insufficient to prevent \nthe grave resource adequacy concerns that led PJM to file the instant proposal in the first \nplace. We think it clear that PJM’s ordinary instrument for procuring sufficient capacity \nto meet PJM’s reliability requirement, the RPM, has failed to keep pace with the \nunprecedented influx of large load into the PJM Region in recent years. \nThe existing Reliability Backstop Auction provision in PJM’s Tariff may be unjust \nand unreasonable because it has failed to remedy these reliability concerns.38 As PJM \nstates, the Reliability Backstop Auction, which was proposed over 20 years ago and has \nnever been used, was not designed to respond to the circumstances surrounding PJM’s \ncurrent capacity shortfall.39 The Reliability Backstop Auction is triggered after three \nconsecutive BRAs clear with a total unforced capacity amount that is more than one \npercent below PJM’s reserve margin.40 As stated above, PJM’s last two BRAs have \ncleared more than five percent below PJM’s reserve margin. Moreover, once the \nReliability Backstop Auction is triggered, PJM cannot run the auction until it “make[s] a \nfiling with FERC for approval to conduct a Reliability Backstop Auction.”41\nThe aspects of the existing Reliability Backstop Auction discussed above call into \nquestion the sufficiency of the current Tariff mechanism to adequately respond in a \ntimely manner to the magnitude of the resource adequacy challenges that the PJM Region \n37 If PJM does make such a filing, the Commission could still modify such a filing \nunder the Western Resources approach described above. \n38 PJM, Intra-PJM Tariffs, OATT, attach. DD, § 16 (Reliability Backstop) (2.0.0). \n39 Transmittal at 29. \n40 PJM, Intra-PJM Tariffs, OATT, attach. DD, § 16 (Reliability Backstop) (2.0.0), \n§ 16.3(a)(i). \n41 Id."},{"page":12,"startToken":4335,"endToken":4767,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 12 - \nfaces today. We therefore conclude on a preliminary basis that the existing Reliability \nBackstop Auction Tariff provisions may be unjust and unreasonable. \n2.\nCertain Aspects of PJM’s Proposal Are Just and Reasonable \na.\nSeller Eligibility Requirements, Sell Offers, and RPM \nMust-Offer Requirement \ni.\nFiling \nLike offset capacity, RBP Resources (i.e., resources that bid into the RBP auction) \nmust have never cleared in an RPM Auction and must have an expected in-service date \nby June 1, 2032.42 PJM, however, states that because RBP Resources have longer-term \ncommitments and price certainty—as compared to resources that provide offset \ncapacity—PJM proposes more restrictive criteria for RBP Resources to limit them to \nthose resources that have demonstrated a high likelihood of success in reaching \ncommercial operation in the near term and remaining available throughout the \ncommitment period. Thus, some categories of resources eligible to be offset capacity \ncannot be RBP Resources, including resources that increase UCAP by switching fuels \nand ELCC class but do not bring on new ICAP. Similarly, any incremental capacity \ncreated by new Capacity Interconnection Rights (CIRs) must also be associated with an \nincrease in ICAP. PJM states that resources relying on Surplus Interconnection Service \nto provide new UCAP MW do not qualify because these resources do not have any \nindependent rights to the PJM system.43 PJM explains that, by design, a surplus resource \ncan only operate while the existing resource is in service, or no more than one year after \nthe deactivation of the existing resource, and when the existing resource is not operating \nand using the interconnection service. PJM states that given the 15-year term of the RBP \ncommitment period, resources need to be able to operate independently to provide \ncertainty of deliverability for a 15-year term. Finally, Demand Resources and DER \nAggregators without identified sites and a 15-year agreement in place cannot be RBP \nResources.\nEach RBP Sell Offer must include: (1) the quantity (MW (UCAP)) to be provided \nby the RBP Resource for each delivery year where the maximum UCAP included in an \nRBP Sell Offer shall be limited to no greater than 120% of the resource type’s most \nrecent maximum Preliminary ELCC Class Ratings for 2028/2029 delivery year through \nthe last posted delivery year or based on the resource’s maximum estimated unit-specific \nELCC ratings across such period for resources with no ELCC Class Rating, multiplied by \nthe resource’s ICAP; and (2) the price in $/MW-day UCAP for each delivery year \n42 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(a). \n43 Transmittal at 52-54."},{"page":13,"startToken":4767,"endToken":5272,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 13 - \nbeginning with the first full delivery year in which the RBP UCAP MW is expected to \nprovide capacity through the 2042/2043 delivery year.44 PJM states that the 120% \nquantity cap reflects the fact that a resource’s Accredited UCAP value may change from \nyear to year.45 PJM argues that allowing sellers to offer amounts greater than the UCAP \ndetermined through current ELCC modeling allows sellers to offer their expected UCAP \nlevels in future years while limiting the risk of overestimated expected UCAP values. \nPJM argues the cap represents a reasonable balance between providing the seller with \nflexibility and managing UCAP risk for load.46\nSellers are responsible for all actual Network Upgrade costs as determined through \nthe interconnection process, without any subsequent adjustments to RBP Sell Offers.47\nSellers reflect in their RBP Sell Offers the anticipated cost of any Network Upgrades, \nestimated or final, associated with the RBP Resource’s provision of capacity. \nTo avoid double procurement, PJM proposes to require a committed RBP Resource \nto offer its available capacity, up to the total quantity of committed RBP UCAP MW, \ninto the RPM Auctions as a price-taker, i.e., $0/MW-day UCAP, beginning with the first \nRPM Auction following the RBP commitment, for the applicable offered delivery year in \nwhich the term of the committed RBP UCAP MW begins and continuing each subsequent \ndelivery year through the end of the fixed term.48 All RBP Resources that offer and clear \n44 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(e). \n45 Transmittal at 55. \n46 PJM notes that the 120% cap is comparable to Southwest Power Pool, Inc.’s \nrecently proposed cap to High Impact Large Load Generation Assessment Customer’s \ngenerating facility’s projected capacity accreditation value (i.e., the higher of 125% or \n110% plus the highest approved Planning Reserve Margin), which the Commission found \njust and reasonable. Transmittal at 55-56 (citing Sw. Power Pool, Inc., 194 FERC ¶ 61,031, \nat P 66 (2026)). \n47 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(e). \n48 Transmittal at 57, 80-81, 126, 130; Proposed Tariff, attach. DD, § 18.6 (0.0.0), \n§ 18.6(a). The only exception to this general rule is that if an RBP Resource has an RBP \ncommitment beginning with the 2029/2030 delivery year and is not the subject of a notice \nof intent to be offered into the BRA for the 2029/2030 delivery year, such RBP Resource \nwould be required to be offered into the Second Incremental Auction for the 2029/2030 \ndelivery year. Proposed Tariff, attach. DD, § 5.5 (Eligibility for Participation in RPM) \n(7.0.0), § 5.5(b). PJM states that this exception is necessary because a Planned \nGeneration Capacity Resource that is not the subject of a notice of intent to offer would \nnot have been included in the planning parameters for the 2029/2030 BRA. Transmittal \nat 57. PJM also proposes Tariff changes to its must-offer exceptions so that an RBP"},{"page":14,"startToken":5272,"endToken":5654,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 14 - \nin the RPM are paid RPM Auction Credits in accordance with RPM rules, and then are \nsettled based on the contract-for-difference design for the RBP UCAP MW.49 All load \nthat is allocated RBP Charges and participates in the RPM will likewise be charged RPM \nCharges and be charged or receive RBP Charges, based on the contract-for-difference \nsettlement. PJM states that RBP Credits and Charges are only assessed to the extent that \nRBP UCAP MW are committed in the RPM and physically available for dispatch in the \nrelevant delivery year.50\nii.\nResponsive Pleadings \nThe Market Monitor is critical of several aspects of PJM’s proposed eligibility \nrequirements for RBP Resources. To begin with, the Market Monitor faults PJM’s \nproposal for not matching the duration of supply with the duration of data center demand, \nwhich is 8,760 hours per year.51 The Market Monitor argues that because a four-hour \nbattery is eligible to be an RBP Resource, there is a significant mismatch between the \nsupply of energy from the battery and the demand for energy from data centers, plus the \ncharging demand of the battery. The Market Monitor states that the same issue exists for \nstandalone solar resources. According to the Market Monitor, the result of this mismatch \nwill be higher energy prices for all PJM customers because PJM will need to dispatch \nhigher-cost resources to meet energy demand. \nThe Market Monitor maintains that permitting Demand Resources and DER \nCapacity Aggregation Resources to serve as RBP Resources creates capacity that is \nmaterially inferior to Generation Capacity Resources.52 The Market Monitor states that \ncommitted generation is required to participate in PJM’s day-ahead energy market and \nmake itself available for economic dispatch. In contrast, the Market Monitor asserts, \ncommitted Demand Resources are only available when PJM invokes emergency \nprocedures. The Market Monitor argues that this is analogous to permitting RBP offset \ncapacity to classify its committed ICAP as maximum emergency, requiring PJM to \ninvoke emergency procedures to access its reliability benefit. \nResource cannot avoid the must-offer requirement by exporting its capacity or removing \nits capacity resource status. Id. at 57-60. \n49 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(g). \n50 Transmittal at 81. \n51 Market Monitor Protest at 18-19. \n52 Id. at 22."},{"page":15,"startToken":5654,"endToken":6078,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 15 - \nThe Market Monitor contends that PJM’s proposed qualifying criteria for RBP \nResources include uprates, Demand Resources, and DER Aggregation Resources—even \nthough the goal of the RBP should be to support new generation and to prevent gaming of \nthe rules by reclassifying existing capacity resources as new.53 The Market Monitor \nargues that the definition should instead ensure that all cleared capacity represents \ninvestment in new physical supply rather than redefining existing resources. \nAEU, on the other hand, argues that proposed eligibility rules for Demand Resources \nand DER Aggregation Resources present unnecessary barriers to entry.54 For example, \nAEU notes that, under the proposal, every site backing a commitment must be locked in \nbefore the resource can bid, for a term length that few demand-side commercial agreements \ncan support. \nJCA argues that PJM’s proposal to accept only commitment terms that terminate \nin the 2042/2043 delivery year excludes resources that can energize in time for the \n2028/2029 delivery year but are unwilling or unable to be bound through the 2042/2043 \ndelivery year. JCA notes that the Charles River Associates Survey Results showed that \n21% of responding suppliers would agree to terms of 10 years or less.55 JCA asserts that \nPJM’s only support for the 15-year payout period is that it is needed to comply with the \nNEDC/PJM Governors’ Principles. JCA contends that it is also unduly discriminatory to \nrequire some ratepayers to pay for 15-year procurements when other ratepayers are \ninsulated from RBP Charges due to offset capacity with terms of only five years.56\nAccording to JCA, PJM’s assertion that a five-year contract is sufficient to satisfy the \nRBP’s short-term reliability need cannot be squared with a proposal requiring 15-year \ncommitments to meet the same need. \n53 Id. at 20. The Market Monitor notes that PJM’s criteria in proposed Tariff, \nAttachment DD, Section 18.5(b), uses the capitalized term Installed Capacity, but there is \nno proposed definition or definition in the existing Tariff. \n54 AEU Comments at 18-22; see also NJBPU Comments at 4-5 (advocating for \nmore flexibility for the participation of Demand Resources and DER Aggregation \nResources). AEU also argues that PJM’s proposal contains unnecessary barriers to \nparticipation for Surplus Interconnection Service resources. AEU suggests several \n“opportunities to enhance the RBP” but also states that PJM’s proposal is “good enough” \nif any of the suggestions would delay the RBP. AEU Comments at 5. \n55 JCA Protest at 14 (citing Charles River Associates Survey Results at 5). \n56 Id. at 17, 34."},{"page":16,"startToken":6078,"endToken":6495,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 16 - \nIn response, PJM argues bilateral arrangements for new capacity are \ndistinguishable from the RBP procurement mechanism.57 PJM contends that parties \nentering into bilateral arrangements are not similarly situated to either the suppliers \noffering into the RBP or the LSEs that are allocated cost responsibility for RBP UCAP \nMW, as bilateral arrangements are privately negotiated business deals. PJM states that \nbecause bilateral arrangements remain the preferred approach to meeting the resource \nadequacy shortfall, establishing less stringent terms for offset capacity encourages parties \nto enter into bilateral arrangements and, thus, decrement the RBP procurement target and \nreduce the quantity of UCAP MW that would otherwise be subject to the more \ninterventionist RBP framework. PJM states that it intends the 15-year term to motivate \nsupply to participate in meeting the procurement shortfall in a timely manner where other \nmeasures have failed. \nParties take various stances on PJM’s proposal to require RBP Sell Offers to \ninclude the quantity of UCAP to be provided for each delivery year where the maximum \nUCAP included is limited to no greater than 120% of the resource type’s most recent \nmaximum Preliminary ELCC Class Ratings for 2028/2029 delivery year through the last \nposted delivery year or based on the resource’s maximum estimated unit-specific ELCC \nratings across such period for resources with no ELCC Class Rating, multiplied by the \nresource’s ICAP. AEU asserts that PJM’s proposal unreasonably places “unhedgeable \nELCC risk” on suppliers and advocates that the risk be shifted to the RPM Auctions, \nwhich would lower RBP bids.58 Equinix, on the other hand, supports PJM’s proposal, \narguing that load contracting today cannot price accreditation risk 15 years forward, and \nthat a floating credit would transfer to load a modeling risk it has no ability to manage.59\nThe Market Monitor argues that the proposed ELCC-related rules would permit \ngenerators to sell more capacity than they have and to do so without penalty for \noverstating capacity. The Market Monitor argues that allowing RBP Sell Offer UCAP \nMW values up to 120% of the maximum preliminary ELCC class rating for 2028/2029 \nthrough the last posted delivery year will overstate the RBP cleared MW and “require \ncustomers to pay for nonexistent capacity.”60\nConstellation, NRG, and Policy Integrity argue that PJM’s proposal to require \nRBP Resources to offer into the RPM Auctions as price-takers will likely suppress RPM \n57 PJM Answer at 32-36. \n58 AEU Comments at 8-9. \n59 Equinix Comments at 13. \n60 Market Monitor Protest at 14."},{"page":17,"startToken":6495,"endToken":6978,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 17 - \nprices, leading to premature generator retirements and artificial shortages.61\nConstellation asserts that these price-formation and reliability risks are most acute when \nRBP Resources enter the RPM Auctions before the associated demand materializes, even \nif that demand eventually materializes. In response, PJM asserts that the Commission has \nconsistently rejected the position that requiring resources that are procured outside of a \ncapacity market to offer into the capacity market as price-takers would unjustly and \nunreasonably distort or suppress capacity market clearing prices.62 PJM argues that the \nCommission has consistently found that the interest in avoiding double-payment \noutweighs the concern of potential price distortion or price suppression.63 PJM contends \nthat Constellation and NRG’s positions effectively recycle arguments previously made \nwith respect to reliability-must-run resources that have been consistently and summarily \ndispatched by the Commission. PJM also argues that RBP Resources should not be \nexcluded from capacity auctions because it could artificially inflate RPM clearing prices \nor require loads to be double charged for capacity.64 In response, P3 asserts that \nreliability-must-run contracts are localized, short-term measures and therefore are \n61 Constellation Protest at 5-10; NRG Protest at 4; Policy Integrity Comments \nat 11. See also P3 Answer at 2, 5, 6-7. \n62 PJM Answer at 47 (citing PJM Interconnection, L.L.C., 190 FERC ¶ 61,088, \nat P 50 (2025) (rejecting, inter alia, Constellation’s arguments against offering reliability-\nmust-run resources into the RPM as price-takers); ISO New Eng. Inc., 165 FERC \n¶ 61,202, at P 65 (2018), order addressing arguments raised on reh’g, 173 FERC \n¶ 61,204 (2020); N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,116 (2015); N.Y. Indep. \nSys. Operator, Inc., 155 FERC ¶ 61,076 (2016); N.Y. Indep. Sys. Operator, Inc., \n161 FERC ¶ 61,189 (2017), order on reh’g, 163 FERC ¶ 61,047 (2018)). \n63 Id. at 48 (citing PJM Interconnection, L.L.C., 137 FERC ¶ 61,145, at P 208 \n(2011) (accepting PJM’s proposed approach to self-supply resources in capacity auction \nfinding that “it appropriately balances the need to protect against uneconomic entry while \nalso mitigating parties’ concerns about having to pay twice for capacity as a result of \nfailing to clear in RPM.”); ISO New Eng. Inc., 173 FERC ¶ 61,198, at P 74 (2020) \n(“[P]rice suppression was an acceptable byproduct of market rules that would attract new \nentry through greater investor assurance and protect consumers from very high year-one \nprices.”) (citation omitted)); see also ISO New Eng. Inc., 155 FERC ¶ 61,023, at P 68 \n(2016) (finding that, where ISO New England Inc. (ISO-NE) sought to “balance both the \nharms and the benefits to customers from an exemption that might result in some price \nsuppression,” the exemption was just and reasonable because ISO-NE “took steps to limit \nthe amount of price suppression” and enabled the continued procurement of “sufficient \ncapacity to meet reliability targets”). \n64 Id. at 49-50."},{"page":18,"startToken":6978,"endToken":7373,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 18 - \nfundamentally distinct from RBP capacity which involves long-term multi-gigawatt \nnew generation.65 P3 avers that applying this to RBP will expand a limited construct, \ncompounding market disruption and undermining market efficiency and resource \nadequacy across PJM.66 P3 and Constellation argue that PJM does not consider the \ncontext of the Commission’s decision to require reliability-must-run units to participate \nas price-takers, including that it was time-limited to two auctions to avoid sustained \ndisruption to the market.67 P3 requests that the Commission modify PJM’s proposal, \ndefer action on this matter to a future proceeding, or establish a paper hearing.68\nNRG argues that the Commission should impose a price floor on offers to \nprevent price distortion in the event the expected load does not materialize. In response, \nPJM argues that there will be a price floor that will apply to all resources offering into the \nRPM through the 2029/2030 delivery year and that a further extension of the price floor \nwould be an impermissible attempt to expand the Minimum Offer Price Rule.69\nConstellation contests PJM’s proposal to exclude from the RBP an existing \nEnergy Resource that has no CIRs but is seeking new CIRs through an Interconnection \nRequest, even if the resource otherwise satisfies the RBP eligibility criteria.70\nConstellation explains that an existing Energy Resource necessarily has an existing \nMaximum Facility Output—not a “new Maximum Facility Output,” as required by PJM’s \nproposed eligibility rules—and obtaining new CIRs does not create a new Maximum \nFacility Output. Constellation asserts that the relevant attribute from a resource adequacy \nperspective is the new CIRs. Constellation concludes that excluding an otherwise \neligible resource because its Maximum Facility Output is not “new” and because it is \ncurrently not a capacity resource but is seeking to obtain new CIRs is unjust and \nunreasonable. In response, PJM argues that the requirement that generation RBP \nResources have a new Maximum Facility Output and new CIRs ensures that eligible \nresources meet stringent standards before receiving 15 years of price certainty.71\n65 P3 Answer at 3-4. See also Constellation September 21 Answer at 6-7. \n66 P3 Answer at 5. \n67 P3 Answer at 5-6; Constellation September 21 Answer at 5-8. \n68 P3 Answer at 7-8. \n69 NRG Protest at 4, 10; PJM Answer at 51-52. \n70 Constellation Protest at 13-14. \n71 PJM Answer at 41."},{"page":19,"startToken":7373,"endToken":7823,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 19 - \nPJM states that it has identified a typographical error in proposed Tariff, \nAttachment DD, section 18.5(d).72 PJM states that the section erroneously requires \nDER Capacity Aggregation Resources to meet the requirements in section 18.5(b), which \nis the provisions for “Generation or Energy Storage Resources as an RBP Resource.” \nRather, PJM states, PJM’s intent was to refer to the general requirements for all \nresources, in Tariff, Attachment DD, section 18.5(a), “RBP Seller Eligibility to \nParticipate and General Requirements for Resources Supporting RBP UCAP MW.” \nPJM therefore requests that the Commission permit PJM, on compliance, to revise the \nproposed Tariff language to replace the reference to section 18.5(b) with section 18.5(a). \niii.\nDetermination \nAs a general matter, we find that PJM has demonstrated that its proposed \neligibility requirements for RBP Resources are just and reasonable. Specifically, we \nagree with PJM that its proposed eligibility requirements will limit RBP Resources to \nthose resources that have demonstrated a high likelihood of success in reaching \ncommercial operation and remaining available throughout the RBP commitment period, \nwhile not being so restrictive as to foreclose significant auction participation. We further \nfind that the stringency of the eligibility requirements for RBP Resources is reasonable \ngiven the revenue certainty that they will obtain over the RBP commitment period should \nthey clear the RBP auction. \nWe disagree with the Market Monitor that PJM should have attempted to match \nthe duration of supply with the duration of data center demand. The same energy must-\noffer requirements apply to RBP Resources based on their resource type as would apply \nto any other resource of that type that cleared the RPM Auctions. Similarly, we disagree \nwith the Market Monitor’s arguments that uprates, Demand Resources, and DER \nAggregation Resources should not be eligible RBP Resources. The Commission has \ndismissed similar arguments from the Market Monitor in the context of the RPM.73\nWe acknowledge AEU’s concern that few Demand Resources and DER \nAggregation Resources can lock in their customers for 15 years, as PJM’s proposal \nwould require for them to qualify as RBP Resources. We find, however, that PJM’s \nproposal is nonetheless reasonable. As PJM explains, in return for the revenue certainty \nthat participating in the RBP auction will provide, it is reasonable to expect these \n72 Id. at 46. \n73 See, e.g., Indep. Mkt. Monitor for PJM vs. PJM Interconnection, L.L.C., \n155 FERC ¶ 61,059, at P 29 (2016) (disagreeing with the Market Monitor’s argument \nthat a day-ahead energy market must-offer requirement must be imposed on capacity \ndemand response resources to treat them on a fully comparable basis relative to \ngeneration capacity resources)."},{"page":20,"startToken":7823,"endToken":8279,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 20 - \nresources to be available during the entire RBP commitment period.74 Like any other \nresource type, Demand Resources and DER Aggregation Resources that cannot commit \nthemselves through the 2042/2043 delivery year are not eligible to participate in the RBP \nas RBP Resources, but—as is the case today—they continue to have the opportunity to \nparticipate in PJM’s routine RPM Auctions. We also disagree with JCA that PJM cannot \nreasonably propose to terminate all RBP Resource commitment terms in the 2042/2043 \ndelivery year and should instead allow for shorter commitment terms. We note that this \nrequirement aligns with PJM’s proposed clearing mechanism, described below, which we \nfind to be just and reasonable. \nWe are unpersuaded by Constellation’s argument that PJM’s proposal to exclude \ngeneration resources that could provide new CIRs, but no new installed capacity, is \nunjust and unreasonable. On the contrary, we agree with PJM that the RBP price \ncertainty of up to 15 years should be used to attract both new installed capacity and new \nCIRs. \nWe find just and reasonable PJM’s proposal to require RBP Sell Offers to include \nthe quantity of UCAP to be provided for each delivery year where the maximum UCAP \nincluded is limited to no greater than 120% of the resource type’s most recent maximum \nPreliminary ELCC Class Ratings for 2028/2029 delivery year through the last posted \ndelivery year or based on the resource’s maximum estimated unit-specific ELCC ratings \nacross such period for resources with no ELCC Class Rating, multiplied by the resource’s \nICAP. We agree with PJM that the proposed cap represents a reasonable balance \nbetween providing sellers with flexibility and managing UCAP risk for load. Under \nPJM’s proposal, load pays for only RBP capacity delivered.75 Thus, the only risk is that \nPJM procures 20% more capacity on paper than what eventually materializes. We are \nnot persuaded that such potential harm renders this component of PJM’s proposal unjust \nand unreasonable. Instead, we find an actual procurement that may result in up to 20% \nless capacity than the estimated target to be acceptable in the context of an estimated \n74 Transmittal at 52 (“Recognizing that RBP Resources will have longer-term \ncommitments and price certainty . . . PJM is proposing comparatively more restrictive \ncriteria for participating resources to help ensure that resources participating in the RBP \nare limited to those that have demonstrated a high likelihood of success in reaching \ncommercial operation in the near term and remaining available throughout the \ncommitment period.”); PJM Answer at 44 (“The [15-year contract] requirement \nultimately provides PJM confidence that DR/DER serving as RBP Resources will \nactually be available for the term of the RBP commitment.”). \n75 Proposed Tariff, attach. DD, § 18.5(g)(i)."},{"page":21,"startToken":8279,"endToken":8711,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 21 - \nresource adequacy shortfall of 6,831 MW, particularly as compared to the total MW of \ncapacity that cleared in PJM’s 2028/2029 BRA. \nWe also disagree with arguments against PJM’s proposal to require RBP \nResources to offer into the RPM Auctions as price-takers because the requirement \nwill likely suppress RPM prices, leading to premature generator retirements and \nartificial shortages. As PJM notes, the Commission has consistently found that \nRegional Transmission Organizations and Independent System Operators can reasonably \nrequire resources that are compensated outside of the capacity market because they are \nneeded to maintain reliability to offer as price-takers in capacity auctions to avoid double \nprocurement, even at the risk of price suppression.76 Here, where PJM is proposing to \nprocure RBP Resources outside of its routine RPM Auctions because those auctions have \nfailed to secure sufficient capacity to meet the PJM Region’s reliability requirements, we \nfind that it is likewise just and reasonable to require RBP Resources to offer into PJM’s \nRPM Auctions as price-takers to avoid the risk of over-procuring capacity through those \nauctions. \nFinally, we acknowledge PJM’s request that the Commission exercise its discretion \nto correct a typographical error in proposed Tariff, Attachment DD, section 18.5(d). If \nPJM were to choose to expeditiously submit an FPA section 205 filing, PJM may decide \nwhether to include that proposed revision. \nb.\nAverage-Price Cap and Clearing Mechanism \ni.\nFiling \nPJM proposes that the levelized procurement cost of all selected RBP Sell Offers \nnot exceed a maximum willingness to pay of $555/MW-day, on a MW-weighted average \nbasis over all delivery years of the RBP.77 PJM notes that earlier this year the \nCommission accepted a price cap of $555/MW-day for the 2028/2029 BRA, and that but \n76 PJM Interconnection, L.L.C., 196 FERC ¶ 61,098, at P 21 (2026) (finding \nthat PJM’s proposal to include reliability-must-run units in the RPM supply stack \nas price-takers is just and reasonable and consistent with Commission precedent \nregarding the treatment of reliability-must-run resources in other regions) (citing PJM \nInterconnection, L.L.C., 193 FERC ¶ 61,234, at P 10 (2025) (citing PJM Interconnection, \nL.L.C., 190 FERC ¶ 61,088, at P 50 (2025) (citing Indep. Power Producers of N.Y., Inc. \nv. N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,214 (2015); N.Y. Indep. Sys. Operator, \nInc., 150 FERC ¶ 61,116 (2015), order on reh’g & compliance, 155 FERC ¶ 61,076 \n(2016), order on reh’g & compliance, 161 FERC ¶ 61,189 (2017); ISO New Eng. Inc., \n165 FERC ¶ 61,202 (2018)))). \n77 Transmittal at 61."},{"page":22,"startToken":8711,"endToken":9161,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 22 - \nfor the lower temporary price cap, the BRA would have cleared at this cap.78 PJM \nexplains that, given that the Initial RBP Target is based on the 2028/2029 BRA shortfall, \nPJM proposes $555/MW-day as the cap to what load will pay for RBP capacity. PJM \nargues that this “budget approach” allows the RBP to manage costs while not restricting \nSell Offers to a hard price cap, and allows for potentially fluctuating offers across the \n15 delivery years of the RBP term. \nPJM argues that the proposed maximum willingness to pay balances the need to \nprocure capacity and maintain system reliability—recognizing that prices above the \n$555/MW-day cap in some delivery years may nevertheless be appropriate under scarcity \nconditions—with consumer protection considerations by requiring that, ultimately, the \naverage procurement price not exceed $555/MW-day over the RBP term. PJM further \nargues that a MW-weighted average provides sellers flexibility not offered by hard caps \non RBP Sell Offers. PJM argues that setting a maximum is necessary because the RBP is \nnot disciplined by direct buy bids that explicitly express willingness to pay, and it is not \nreasonable to assume that load should be obligated to pay an unlimited amount for \nsupply. PJM argues that it is reasonable to conclude that PJM’s willingness to pay for a \n15-year commitment should not exceed the amount that load would be willing to pay for \na single-year commitment under the RPM framework, given the benefits to supply \nresources of revenue certainty and the chance to reduce financial and development risk \nand improve financing opportunities through lower capital costs or more favorable \nfinancing terms.79\nPJM proposes to commit RBP Resources using a pay-as-bid approach, which PJM \nargues is more appropriate for a one-time backstop procurement than the single-clearing-\nprice approach used in the RPM.80 First, PJM argues that because the RBP is a one-time \nprocurement, its pricing outcomes are less likely to serve as market signals. Second, PJM \nnotes that the RBP will not be procuring a uniform commodity because resources may \ndiffer based on commercial operation dates, Network Upgrades, and other factors. Third, \nPJM states that a uniform clearing price would require PJM to normalize offers through \npotentially complex and subjective assumptions. \n78 Id. at 62 (citing PJM Interconnection, L.L.C., 194 FERC ¶ 61,049, at PP 44-45, \norder on reh’g, 196 FERC ¶ 61,007 (2026)). \n79 Id. at 63-64. \n80 Id. at 65. PJM states that the Commission has previously found it just and \nreasonable to pair a pay-as-bid approach to backstop procurement with a maximum \nwillingness to pay. Id. (citing Cal. Indep. Sys. Operator Corp., 153 FERC ¶ 61,001 \n(2015))."},{"page":23,"startToken":9161,"endToken":9618,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 23 - \nFor RBP Resources to clear the auction, PJM proposes to first filter prospective \nresources through “gating” criteria, which PJM argues will ensure that the selected RBP \nResources are those most likely to go into service and will deter speculation.81 For \ngeneration and storage resources, the seller must provide: (1) a critical path construction \nschedule supporting the feasibility of a commercial operation date of June 1, 2032, or \nearlier; (2) interconnection study information and a development timeline appropriate to \nits interconnection queue study process; (3) evidence of 100% site control; (4) a financing \nplan showing that the resource has sufficient financial backing; (5) a permitting plan \nshowing that the developer is on track to obtain all necessary permits; and (6) evidence \nthat the developer has or will procure the necessary major equipment. In addition, the \nseller must demonstrate that it is able to develop the underlying resource by providing \n“[e]vidence of experience having constructed a previous project of similar size and \ntechnology or have contracted with an engineering, procurement, and construction partner \nwith such experience.”82 A seller offering RBP UCAP MW based on a natural-gas-fired \nresource must provide evidence of a delivering pipeline. To the extent the resource is \nlocated outside the PJM Region, the seller must demonstrate that the resource has \nprogressed through its host region’s interconnection study process to obtain a completed \nfacilities study or the equivalent and, consistent with PJM’s pseudo-tie requirements, a \nlong-term firm point-to-point transmission service, or a confirmed transmission service \nrequest with a completed system impact study, sufficient to deliver capacity to PJM’s \nborder. \nFor Demand Resources and DER Capacity Aggregation Resources, the seller \nmust provide evidence of the locations within PJM of the load reduction and executed \ncustomer agreements or binding commitments with identified locations and customer \nnames sufficient to cover the offered MW quantity.83 The seller must also show that it \nwill be able to effectuate the offered load reduction through evidence of an “[e]quipment \nprocurement plan or evidence of deployed enabling infrastructure such as metering, \ntelemetry, load control, [Supervisory Control and Data Acquisition]/dispatch systems, or \nDER major equipment as applicable.”84\nAfter applying the gating criteria, PJM evaluates the RBP Sell Offers based on the \nfirst delivery year offered in the RBP Sell Offer, levelized cost, and RBP UCAP MW \nquantity. The proposed selection process first orders all Sell Offers based on the \n81 Id. at 71. PJM also notes that it will give sellers an opportunity to cure any \nPJM-identified deficiencies. Id. at 72. \n82 Id. at 73 (quoting Proposed Tariff, attach. DD, § 18.5(f)(i)(6)). \n83 Id. at 74. \n84 Id. at 75 (quoting Proposed Tariff, attach. DD, § 18.5(f)(i)(11))."},{"page":24,"startToken":9618,"endToken":10107,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 24 - \nresource’s identified offered delivery year, and then by price, by ordering the RBP Sell \nOffers “in least-cost order based on the levelized cost ($/MW-day) of UCAP MW over \nthe fixed 15-year term.”85 From this stack of offers, PJM proposes to select RBP Sell \nOffers until the Final RBP Target is satisfied. PJM explains that because all RBP \ncommitments terminate with the 2042/2043 delivery year regardless of which delivery \nyear the RBP Resource first offered, the levelized cost determination is needed for a \ncomparative evaluation for each resource for the period between commercial operation \nand the 2042/2043 delivery year. PJM explains that a levelized cost accounts for the time \nvalue of money, which is critical when evaluating contracts spanning 15-year terms, as \nPJM is proposing in the RBP. PJM explains that levelized cost will be calculated as: \nLevelized Cost ($/MW-day) = Net Present Value (RBP Sell Offer price * UCAP \noffered)/Net Present Value (UCAP offered), with a discount rate equal to 9.5% after-tax \naverage weighted average cost of capital.86\nPJM explains that, in selecting resources from the offer stack, it will first look to \nRBP Resources expected to reach commercial operation in the 2028/2029 delivery year. \nIf that set of resources is insufficient to meet the Final RBP Target, then PJM will apply \nthe selection criteria to consider all resources offered with an expected commercial \noperation date in the 2029/2030 delivery year, and will continue iteratively, up to \nand including the 2032/2033 delivery year, until the set of offers selected meets the \nFinal RBP Target. PJM further explains that, within this selection process, it will not \nprocure a resource that results in the MW-weighted average of the levelized procurement \ncost exceeding $555/MW-day, meaning that it may skip over a resource with an earlier \ndelivery year if procuring that resource would violate the maximum willingness to pay \nfor the procurement.87 If a resource is skipped because it violates the cap but a lower-\ncost resource is procured that then creates “room in the budget” to select that higher-\noffer-earlier delivery year resource, the selection process will go back to procure that \nresource before continuing down the rank-order of additional offers in later delivery \nyears. PJM explains that the selection process prioritizes earlier delivery years to address \nthe shortfall target as soon as possible. PJM also states that, in procuring the least-cost \nset of resources, it may clear an RBP Sell Offer with an offered quantity that exceeds the \nremaining Final RBP Target if the solution results in a lower overall cost than the \nalternative.88 That is, PJM may exercise the option to procure more capacity than the \nFinal RBP Target if, compared to acquiring a resource with a higher offer price that \n85 Id. (quoting Proposed Tariff, attach. DD, § 18.5(f)(ii)). \n86 Id. at 76-77. \n87 Id. at 78. \n88 Id. at 79."},{"page":25,"startToken":10107,"endToken":10532,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 25 - \nwould not reach the Final RBP Target, PJM would end up paying less overall. PJM \nasserts that this would result in the more economical outcome. Relatedly, PJM notes \nthat because the RBP is procuring new capacity and not simply fungible UCAP MW, \nRBP Resources shall not be partially cleared. Thus, PJM may clear a set of resources \nwith a cumulative RBP UCAP MW total that does not exactly match the Final RBP \nTarget. \nFinally, PJM states that, following the conclusion of the RBP and to the extent \nconsistent with the existing member confidentiality rules, PJM will post a report that, \ninter alia, provides a transparent overview of the aggregate MW that were procured \nthrough the RBP and a weighted average of the RBP Charges as soon as is practicable \nafter the RBP is completed.89\nii.\nResponsive Pleadings \nJCA argues that RBP’s design defeats itself by requiring the purchase of long-term \nresources while constraining the participation of shorter-term resources that could better \nalign with the identified need, and that PJM has not defended the 15-year commitment \nterm as necessary to cure the reliability shortfall. JCA asserts that it is unjust and \nunreasonable to charge ratepayers for the acquisition of years of capacity that is not \nneeded to address the reliability shortfall and serves no cost-efficiency or other economic \npurpose.90\nSeveral intervenors argue that the $555/MW-day cap is too high. JCA argues \nthat the $555/MW-day cap should be substantially less because 15-year price certainty \nreduces supplier risk and eases financing.91 JCA also argues that ratepayers could pay \nmore than $555/MW-day if any resource that bid less fails to materialize or ceases \noperation prior to the end of the RBP term. JCA argues that PJM’s borrowing of Point 1 \nfrom the VRR curve is inapposite because it is a reference cost grounded in the estimated \nCost of New Entry (CONE) for a combustion turbine (CT) reference resource, whereas \nthe RBP has no reference resource or VRR curve. OCC argues that the proposed cap is \nsignificantly higher than the clearing price in the 2028/2029 BRA of $325/MW-day at the \n89 Id.\n90 JCA Protest at 16 (citing Citadel FNGE Ltd. v. FERC, 77 F.4th 842, 856 \n(D.C. Cir. 2023) (explaining that the “application of [a PJM auction rule] was unjust and \nunreasonable not just because of how much it increased the wholesale rate, but because it \ncaused that increase for no justifiable purpose” and “without any commensurate \n[consumer] benefit”)). \n91 Id. at 25."},{"page":26,"startToken":10532,"endToken":10999,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 26 - \nprice cap, which also reflects the scarcity conditions in that auction.92 The Market \nMonitor states that net revenues in the energy market are significantly higher now than \nthey were when PJM calculated the $555/MW-day figure. Therefore, the Market \nMonitor argues, PJM has significantly overstated the maximum price for the RBP.93\nOther intervenors, however, argue the $555/MW-day cap is too low. E-Cubed \nasserts that PJM’s proposed average price cap is not just and reasonable because it is not \nreflective of actual costs, nor will it solve the identified capacity shortfall. E-Cubed \nargues that, based on its analysis of publicly available data, it is unlikely that any capacity \nwill be committed via RBP because the $555/MW-day volume weighted average \nconstraint on purchases in the RBP is not commensurate with the actual cost of bringing \ncapacity into PJM for any resource type.94 NRG argues that there should be no price cap \nbecause the top priority should be allowing the RBP to fulfill its purpose of covering the \ncapacity shortfall. According to NRG, even if a price cap were appropriate, PJM has not \nexplained why a soft cap based on an outdated estimate of CONE for a CT in the last \nquadrennial review is a just and reasonable level. NRG further states that capital costs \nhave escalated sharply since that estimate was calculated. NRG argues that there is no \nlogical reason why the prices paid to individual suppliers in the RBP should be subject to \na cap based on CONE for a CT when the capacity shortfall could be covered with any \nnumber of resources, including resources using different technologies or having other \ncharacteristics that cause their costs to significantly exceed those of the reference CT. \nNRG states that it has a project sufficiently advanced to participate in the RBP that has \ncosts, net of expected energy and ancillary services revenues, that are substantially \ngreater than the $555/MW-day cap, and it would be hard to justify the time and expense \nof offering it into the RBP given its costs and size. NRG argues that if the Commission \ndoes not eliminate the soft cap entirely, it should reset the cap to $866/MW-day.95\nOELC argues that the proposed RBP Resource selection method is not just and \nreasonable because it does not adequately incentivize new dispatchable generation, which \nis most capable of serving load during the reliability risk conditions for which the RBP is \ndesigned. OELC urges the Commission to modify PJM’s proposed resource-selection \nmethod to value new dispatchable generation’s reliability attributes.96\n92 OCC Protest at 8. \n93 Market Monitor Protest at 27. \n94 E-Cubed Protest at 2, 6, 19. \n95 NRG Limited Protest at 5-10. \n96 OELC Comments at 2, 9-10. See also FirstEnergy Protest at 15-17."},{"page":27,"startToken":10999,"endToken":11437,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 27 - \nVoltus argues that the proposed gating criteria for RBP Resource offers do not \nrecognize the commercial development pathways of distributed demand-side resources. \nVoltus notes that, under PJM’s proposal, Demand Resource and DER Capacity \nAggregation offers must “[i]dentify, as part of its RBP Sell Offer, for the full length of \nthe fixed term, the location(s) and associated participation contract(s)” and will only be \nconsidered if they include “[e]xecuted customer agreements or binding commitments \ncovering the proposed RBP UCAP MW commitment, with identified locations, customer \nnames, and expected curtailment/injection capability per site.”97 Voltus argues that this \ngating criterion inverts the development sequence because customer contracts are entered \ninto against a known price and volume (i.e., the output of the auction). According to \nVoltus, requiring customer contracts before the auction removes the commercial basis on \nwhich they would be executed. Relatedly, AEU requests that PJM “confirm . . . that a \nprocurement plan, rather than infrastructure already installed and operational at the time \nof the offer, is sufficient to satisfy” the gating criteria for Demand Resources and DER \nCapacity Aggregation Resources.98 On the other hand, FirstEnergy argues that the gating \ncriteria for demand response contain a significant ambiguity, requiring only a contract or \nagreement evidencing a “plan or evidence of deployed enabling infrastructure,” not one \ndemonstrating a clear and binding commitment to provide the MWs sold into the RBP.99\nFirstEnergy argues that the language risks treating speculative resources as equivalent to \ncommitted resources. FirstEnergy thus requests that PJM clarify that eligible demand \nresponse resources must be supported by binding contractual commitments. \nThe Market Monitor argues that the RBP clearing process is not consistent with \ncost minimizing principles because it favors resources with a commercial operation date \nin 2028/2029 over resources with later commercial operation dates even when the later \nresources are less costly and have better reliability characteristics.100 Some parties \nalso fault PJM’s proposed pay-as-bid structure because, as PJM concedes, sellers in a \npay-as-bid auction bid the expected clearing price, not their marginal costs.101\nCPV supports the proposal but argues that the gating criteria language requires \nclarification to avoid inadvertently narrowing the pool of eligible projects. CPV notes \n97 Voltus Protest at 3, 10-15 (citing Proposed Tariff, attach. DD, §§ 18.5(c)(ii), \n18.5(d)(i), 18.5(f)(i)(10)). See also NJBPU Comments at 4-5. \n98 AEU Comments at 21. \n99 FirstEnergy Protest at 21 (citing Transmittal at 74-75). \n100 Market Monitor Protest at 24-25. \n101 JCA Protest at 6; Market Monitor Protest at 11-13; NJBPU Comments at 4; \nOCC Protest at 7-8."},{"page":28,"startToken":11437,"endToken":11858,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 28 - \nthat the gating criteria require sellers to demonstrate site control for a term of at least \nthree years from the date of submission of an “Application,” but that the Tariff’s \nexisting definition of “Application” has no connection to the RBP.102 CPV proposes \na correction to refer instead to an “RBP Sell Offer.” CPV also argues that proposed \nsection 18.5(f)(i)(2) fails to account for sellers with generation projects currently active \nin PJM’s interconnection queue that have already satisfied the applicable site control \nrequirements that are a condition of advancing through the queue.103 CPV argues that \nrequiring such developers to separately satisfy a new three-year requirement on limited \nnotice could impose an unnecessary additional burden. CPV proposes to clarify that \nproposed section 18.5(f)(i)(2) applies only “[f]or projects without an active queue \nposition.” \niii.\nPJM Answer \nPJM asserts that the arguments that procuring for a fixed term of up to 15 years is \nunjust and unreasonable are without merit. PJM argues that the 15-year term for RBP is \nintended to motivate supply to participate in meeting the procurement shortfall in a \ntimely manner where other measures have failed.104\nRegarding the proposed $555/MW-day price cap, PJM notes that some intervenors \nargue that the cap is too high,105 while others argue that it is too low. PJM highlights \nthat no entity that would ultimately be responsible for paying the RBP Charges raised \nconcerns with the proposed level of the cap. PJM also argues that the fact that some \nintervenors argue that the cap is too high, while others claim that it is too low, is not \nindicative of a flaw in the proposal but rather is an outgrowth of PJM’s concerted effort \nto strike an appropriate balance and find a middle ground that is just and reasonable and \nnot unduly discriminatory or preferential.106 Finally, PJM also argues that the revenue \ncertainty of a 15-year term mitigates concerns that costs have risen since the periodic \nreview that produced the $555/MW-day figure, and notes that while a handful of \nsuppliers argue against the proposed level of the cap, others did not.107\n102 CPV Comments at 4. \n103 Id. at 5. \n104 PJM Answer at 32-35. \n105 Id. at 37 (citing OCC Protest at 8; JCA Protest at 25-28; IMM Protest at 27-28). \n106 Id. at 38-39 (citing E-Cubed Protest at 2; NRG Limited Protest at 6, 10). \n107 Id. at 40 (citing, generally, CPV Comments)."},{"page":29,"startToken":11858,"endToken":12326,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 29 - \nPJM responds to concerns that the proposed gating criteria are too stringent by \narguing that the criteria are appropriately tailored to limit the RBP to new capacity \nwith a high likelihood of coming online.108 PJM states that it will provide sellers the \nopportunity to cure PJM-identified deficiencies and anticipates working hand-in-hand \nwith capacity resources to determine how deficiencies may be cured. In response to \narguments that the gating criteria for Demand Resources and DER Capacity Aggregation \nResources specifically are overly stringent, PJM states that the difference is by design, \nbecause generation/storage resources are tied to physical assets that make it costly to exit \nthe market early, whereas Demand Resources and DER Capacity Aggregation Resources \nare, by nature, contracts or agreements that are not tied to a dedicated asset. PJM also \nnotes that Demand Resources and DER Capacity Aggregation Resources are able to \neasily enter and exit the market based on economic and other business decisions. Finally, \nPJM states that RBP is designed to not allow for replacement of RBP Resources so that \nonly the RBP Resource is eligible for RBP payments, and requiring evidence that the \nDemand Resource/DER locations are contracted for 15 years ensures parity with \ngeneration/storage resources that participate in RBP. \nPJM states that it is amenable to CPV’s suggested revision to the gating criteria \nrequirement that Generating Facilities provide evidence of 100% site control. PJM agrees \nthat the term “Application” may be ambiguous in the proposed Tariff language requiring \nevidence of 100% site control “for a term of at least three years from the date of \nsubmission of the Application,”109 and clarifies that the language was intended to state that \nthe three-year site control requirement would begin from the date when sellers submit \ntheir RBP Sell Offer, as CPV suggested.110 Further, PJM states that CPV’s request to \nclarify that such requirement should only be applicable to projects that do not already have \nan active queue position is reasonable, because projects that are both already in the \ninterconnection queue and already meet the relevant prerequisites to proceed through \nthe queue will have already demonstrated a high likelihood of actualization and success. \nPJM believes that CPV’s suggested redlines to proposed Tariff, Attachment DD, \nsection 18.5(f)(i)(2) to this effect are reasonable. \niv.\nDetermination \nAs a general matter, we find that PJM has shown that its proposed $555/MW-day \nmaximum willingness to pay and process for selecting RBP Resources in the RBP \nauction are just and reasonable. We agree with PJM that a maximum willingness \nto pay set at the MW-weighted average of the levelized procurement cost over the \n108 Id. at 42. \n109 Proposed Tariff, attach. DD, § 18.5(f)(i)(2). \n110 PJM Answer at 44-45 (citing CPV Comments at 4-5)."},{"page":30,"startToken":12326,"endToken":12814,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 30 - \nRBP commitment term reasonably balances the need to expeditiously procure capacity in \nresponse to the PJM Region’s imminent capacity shortfall with ensuring that the average \nprocurement price does not exceed load’s maximum willingness to pay. We further find \nthat in establishing the value for the maximum willingness to pay in the RBP, PJM \nreasonably relied on the value of the RPM price cap that the Commission accepted in \nJanuary and reaffirmed in July.111 We disagree with arguments that the Commission \nmust direct PJM to adopt a value for load’s maximum willingness to pay that is based on \nthe most recent forward prices and production costs. Specifically, we find that using the \n$555/MW-day price cap for the 2028/2029 BRA—which was just approved this January \nand affirmed in July, as noted directly above—is a reasonable proxy of load’s maximum \nwillingness to pay for RBP capacity. \nWe agree with PJM that the proposed pay-as-bid structure for the RBP auction is \nreasonable.112 As PJM explains, the RBP auction is not procuring a uniform product \nbecause RBP Resources may differ based on commercial operation dates and other \nfactors. As such, we find that it is reasonable for each RBP Resource to be paid the price \nthat it bids when offering into the RBP auction. We recognize that, as both PJM and \nprotesters note, sellers are theoretically less likely to offer near their marginal costs in a \npay-as-bid auction than in a single-price auction. We find, however, that this theoretical \ndrawback is acceptable in the context of the proposed $555/MW-day average-price cap \nand the Charles River Associates Survey Results indicating strong seller interest in the \nRBP auction.113\nMoreover, we find that PJM’s proposed gating criteria for RBP Resources are just \nand reasonable. These criteria, which PJM will employ as the first step in the selection \nprocess for RBP Resources, will help to deter speculative resources from bidding into the \nRBP auction and ensure that the selected RBP Resources are those most likely to go into \nservice. Regarding arguments that Demand Resources and DER Capacity Aggregation \nResources cannot feasibly lock in their customers for 15 years before the RBP auction, \nwe find that PJM has justified this requirement as reasonable. Specifically, PJM explains \nthat this restriction is necessary to manage the risk of the supply being available for the \nfull term that PJM is procuring on behalf of load in the RBP.114 Failing to require \nDemand Resources and DER Capacity Aggregation Resources to provide evidence of the \n111 PJM Interconnection, L.L.C., 194 FERC ¶ 61,049, at PP 45-46, 49 (2026), \norder on reh’g, 196 FERC ¶ 61,007, at PP 25-26. \n112 We note that the existing Reliability Backstop Auction also uses a pay-as-bid \nstructure. Tariff, attach. DD, § 16 (2.0.0), § 16.4(e)(2). \n113 Charles River Associates Survey Results at 5. \n114 PJM Answer at 54."},{"page":31,"startToken":12814,"endToken":13235,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 31 - \nexecuted customer agreements or binding commitments with identified locations and \ncustomer names sufficient to cover the offered MW quantity could result in such \nresources contracting with different loads over the life of the RBP commitment term, \ncontrary to its purpose of providing long-term revenue certainty for RBP Resources. \nAdditionally, we disagree with JCA that PJM unreasonably requires commitment terms \nending no earlier than 2042/2043. As PJM explains, long contract terms create revenue \ncertainty for RBP Resources and generally can reduce financial and development risk and \nmay improve financing opportunities through lower capital costs or more favorable \nfinancing terms.115\nPJM explains that, after applying the gating criteria, it would evaluate sell offers \nfirst based on the resource’s identified offered delivery year, then by price, until the \nFinal RBP Target is satisfied. We agree with PJM that this process for selecting RBP \nResources in the RBP auction reasonably prioritizes earlier delivery years to address the \nPJM Region’s capacity shortfall as soon as possible. We disagree with OELC that PJM’s \nproposed process for selecting RBP Resources in the RBP auction is deficient because it \ndoes not value dispatchable generation’s reliability attributes beyond what PJM’s ELCC \naccreditation already captures because we do not find such additional valuation metrics to \nbe necessary for PJM’s proposal to be just and reasonable. \nFinally, we acknowledge PJM’s openness to adopt CPV’s suggested redlines to \nproposed Tariff, Attachment DD, section 18.5(f)(i)(2). If PJM were to choose to \nexpeditiously submit an FPA section 205 filing, PJM may decide whether to include \nthose revisions. \nc.\nRBP UCAP MW Shortfall Charges \ni.\nFiling \nPJM proposes that an RBP UCAP MW shortfall will occur when a committed \nRBP Resource has not reached commercial operation for the relevant delivery year for up \nto three consecutive years unless the RBP Resource qualifies for an exception because it \nis waiting on Network Upgrades.116 Once an RBP Resource has achieved commercial \noperation, PJM proposes that RBP UCAP MW shortfall charges will end but that RBP \nResources are not paid for any RBP UCAP MW not provided. PJM proposes that RBP \n115 Transmittal at 63-64. \n116 Proposed Tariff, attach. DD, 18.6 (0.0.0), § 18.6(d)(i) (“An RBP Resource \nthat is a generation or Energy Storage Resource and is unable to meet [its] expected \ncommercial operation date solely due to Network Upgrades shall be excepted from RBP \nshortfall charges if the RBP Resource successfully demonstrates readiness through test \nenergy and seeks interim deliverability.”)."},{"page":32,"startToken":13235,"endToken":13647,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 32 - \nshortfall charges will be equal to the product of the RBP Resource’s committed RBP \nUCAP MW shortfall and 20% of the RBP price. If the RBP Resource fails to provide \nany RBP UCAP MW after three consecutive delivery years, PJM proposes that the RBP \ncommitment will be rescinded for the remainder of the term. PJM states that it proposes \nto allow RBP Resources to retain RBP UCAP MW commitments for up to three years \nbecause a resource’s commercial operation date may be delayed even when a project is \nviable.117 PJM argues that the limitation on RBP shortfall charges helps reduce the \nbarrier to entry. \nii.\nResponsive Pleadings \nThe Market Monitor contests the proposed RBP UCAP MW shortfall charges, \narguing PJM inappropriately proposes to shift ELCC-related risk from generators to \ncustomers because shortfalls due to decreases in the ELCC ratings are not subject to \npenalties. The Market Monitor argues that generator performance risk is an investor risk \nand not a customer risk, and that one of the benefits of markets is that performance risk is \nassigned to generators because they are responsible for unit performance. The Market \nMonitor contends that the absence of shortfall charges for failure to deliver the quantity \nof UCAP sold shifts the ELCC accreditation risk to load, which must pay for the \nadditional supply to cover the shortfall.118\nThe Market Monitor also argues that PJM unnecessarily restricts the applicability \nof shortfall charges to a narrow reason, is vague about the timing of the charges, and \nunreasonably limits the charges to three years.119 The Market Monitor adds that PJM’s \nproposed criteria for defining shortfall charges are also vague and unenforceable, and that \nPJM has not explained why the RBP penalties vary so significantly from the current RPM \nrules. The Market Monitor states that deficiency charges under the current RPM rules are \nassessed due to a failure to satisfy a commitment “for any reason,” such as derates and \nretirements, whereas the proposed shortfall charges would only apply for commercial \noperation delays. For example, the Market Monitor argues, if a generation project \nconfiguration and MW change significantly but it still achieves commercial operation by \nthe delivery year, it is not clear whether RBP shortfall charges would apply. \nThe Market Monitor further argues that use of the term “commercial operation” \ninstead of the more precise tariff-defined “commencement of Interconnection Service” \n117 Transmittal at 61. \n118 Market Monitor Protest at 14-15. \n119 Id. at 15."},{"page":33,"startToken":13647,"endToken":14064,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 33 - \nlimits the applicability of RBP UCAP MW shortfall charges even more so.120 Also, the \nMarket Monitor states, the term “commercial operation” is generally not a term applied \nto Demand Resources and DER Aggregation Resources, and it is not clear how the \nshortfall charges would apply to these resource types. The Market Monitor states that in \ndefining the eligibility criteria for RBP Resources in proposed Tariff, Attachment DD, \nsection 18.5(a)(i), PJM distinguishes Demand Resources and DER Aggregation \nResources as being registered and under a contract to perform versus having a \ncommercial operation date prior to June 1, 2032. The Market Monitor argues that \nPJM does not explain why this same distinction is not included in the shortfall charge \nprovision. \nThe Market Monitor also contests PJM’s proposed Shortfall Penalty exception for \nunavailability due to delayed Network Upgrades, arguing that the proposal shifts risks \nfrom resource owners to load.121\niii.\nDetermination \nWe find that PJM’s proposed RBP UCAP MW shortfall charges are just and \nreasonable because they will deter speculative resources from seeking to participate in \nthe RBP auction without creating an undue barrier to entry. Under PJM’s proposal, an \nRBP UCAP MW shortfall occurs when a committed RBP Resource has not reached \ncommercial operation for the relevant delivery year for up to three consecutive years. \nRBP shortfall charges are equal to the product of the RBP Resource’s committed RBP \nUCAP MW shortfall and 20% of the RBP price. We find that PJM’s proposal to assess \npenalties at this level, for up to three years, is just and reasonable because these penalties, \nalong with the pay-as-bid RBP clearing price and the promise of up to 15 years of \nrevenue certainty, will incentivize developers of RBP Resources to deliver their RBP \nUCAP MW. \nWe disagree with the Market Monitor’s various criticisms of the proposed \nRBP UCAP MW shortfall charges, including the Market Monitor’s argument that PJM \ninappropriately proposes to shift ELCC-related risk from generators to customers. Under \nthe proposal, LSEs pay RBP Charges for only the RBP UCAP MW delivered. Thus, the \nrisk for customers is that they end up paying for less RBP capacity than they anticipated. \nHowever, PJM’s proposal mitigates this risk because, as discussed above, other aspects \nof the proposal strongly encourage RBP Resources to deliver. \nWe also disagree with the Market Monitor’s arguments that PJM’s proposed Tariff \nrevisions describing the shortfall charges are impermissibly vague, and that the \n120 Id. at 16. \n121 Id. at 17."},{"page":34,"startToken":14064,"endToken":14512,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 34 - \nCommission should reject the proposed exception for unavailability due to delayed \nNetwork Upgrades. On the contrary, we find that this exception is a reasonable approach \nbecause it removes a risk over which RBP Resources have no control. More generally, \nwe are not persuaded by the Market Monitor’s multiple comparisons between the \nproposed RBP rules and the existing RPM rules because the RBP is a stopgap measure to \naddress the failure of the RPM to attract sufficient supply. An intervention, almost by \ndefinition, is not going to be “consistent with PJM’s fundamental market design,” as the \nMarket Monitor contends. \nd.\nLack of Locational Constraints and Market Power \nMitigation \ni.\nFiling \nPJM explains that it does not propose to apply locational constraints in the RBP.122\nPJM states that just as the driver of the RBP is the resource adequacy shortfall at the PJM \nRegion level, the Final RBP Target is based on a regionwide shortfall. PJM states that \nwhile it recognizes there are locational considerations at large for resource adequacy, \nand these constraints are modeled in the RPM Auctions, it is also the case that the RPM \nis an annual three-year forward framework, which allows PJM to model the necessary \nlocational parameters—Capacity Emergency Transfer Objectives (CETO) and Capacity \nEmergency Transfer Limits (CETL)—to accurately capture the locational needs in the \ncapacity market. By contrast, PJM argues, it does not project and calculate these \nparameters 15 years out, which is the eligible term of the RBP, because PJM does not \nhave the information needed to determine such locational parameters for 15-year term \ncapacity commitments. PJM states that as a result, including locational parameters based \non today’s conditions would inevitably skew the results and lead to either over-\nprocurement or under-procurement in given zones based on nothing more than \nspeculation as to the state of the system 10 and 15 years from now. Moreover, PJM \nargues that inclusion of a speculative locational parameter at this point would ignore the \nfact that PJM’s interconnection process ensures the initial deliverability of new capacity \nto the region. PJM also notes that, going forward, the PJM Regional Transmission \nExpansion Plan (RTEP) process annually studies and addresses any transmission \nupgrades needed to ensure the ongoing deliverability of capacity resources. PJM states \nthat load deliverability is also assessed as part of the RTEP process, which will identify \ntransmission needs as load patterns change. \nPJM states that it is also not proposing direct market power screens or mitigation \nfor the RBP because, in the context of a pay-as-bid structure with a $555/MW-day cap, \nthe effectiveness of such measures would be limited. PJM notes that a pay-as-bid \n122 Transmittal at 33-34."},{"page":35,"startToken":14512,"endToken":14913,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 35 - \nstructure, unlike a single-clearing-price structure, does not allow any resource to impact \nthe clearing price of any other resource.123 In addition, PJM states, its proposed average-\nprice cap of $555/MW-day further discipline costs by increasing the risk that high offers \ndo not clear. PJM states that PJM’s proposed average-price cap is similar to the existing \nmarket mitigation rules for Planned Generation Capacity Resources because PJM may \nreject sell offers from those resources if they exceed 140% of an average, relevant \nprice.124\nPJM argues that the risk of economic withholding is limited, because the suppliers \ncan choose whether to participate.125 PJM notes that its maximum procurement target \nunder the RBP is limited to the 2028/2029 BRA shortfall of 6,831 MW. PJM further \nnotes that the Charles River Associates Survey Results identified more than 100 GW \nof prospective supply interested in participating in some form through this process.126\nPJM argues that this level of interest indicates there is available supply that will compete \nto secure an RBP commitment. PJM explains that it also expanded the pool of eligible \nsupply by permitting participation from resources capable of achieving commercial \noperation beyond the timeframe required for the 2028/2029 BRA. PJM contends that \nunder a pay-as-bid structure, such competition should exert downward pressure on \nprocurement costs and improve the efficiency of the RBP procurement process. \nFinally, PJM argues that the implementation of market mitigation measures in a \npay-as-bid construct can be difficult to verify and ineffective.127 PJM states that in a \npay-as-bid approach, unlike a uniform clearing price construct where sellers are expected \nto offer a marginal cost, sellers are more likely to offer the expected clearing price. PJM \nstates that given offers will likely have less variation and information underlying them, it \ncan be difficult and ineffective to determine offers exhorting market power. \n123 PJM states that the Commission, under somewhat similar circumstances, has \npreviously found the pay-as-bid approach to be just and reasonable. Transmittal at 69-70 \n(citing Cal. Indep. Sys. Operator Corp., 153 FERC ¶ 61,001, at PP 2, 8, 15, 28 (2015)). \n124 Transmittal at 66-67, 70 (citing PJM, Intra-PJM Tariffs, OATT ATT DD.6.5, \nOATT ATTACHMENT DD.6.5 Mitigation (2.0.0), § 6.5(a)(ii)(C)). \n125 Id. at 68. \n126 Id. (citing Charles River Associates Survey Results at 5). \n127 Id. at 71."},{"page":36,"startToken":14913,"endToken":15358,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 36 - \nii.\nResponsive Pleadings \nSeveral parties criticize PJM’s RBP proposal for what it lacks. The Market \nMonitor, for example, argues that the PJM RBP proposal would violate fundamental \nelements of the PJM capacity market design, which include the use of a single-price \nclearing mechanism, locational constraints, and market power mitigation rules. The \nMarket Monitor argues that PJM’s decision not to include locational requirements risks \ncustomers paying higher RPM prices in price-separated Locational Deliverability Areas, \nin addition to paying for additional transmission and higher energy prices as expensive \nlocal resources are required to serve data centers rather than the RBP Resources.128\nMany other parties argue that the lack of locational constraints in the RBP is \nunjust and unreasonable. PIOs and JCA argue that the Commission should modify \nthe proposal to require that RBP Resources be sited in the same Electric Distributor \nzone/area as the load they serve, which would avoid costly transmission infrastructure \nbuildout and delays.129 JCA similarly contends that the absence of locational criteria for \nRBP procurements poses unjustified cost risks for ratepayers. AEP avers that the lack of \na locational deliverability requirement could require customers to fund RBP Resources \nthat are not deliverable to their zone, while resources that are necessary to address local \nreliability needs may not be procured at all. \nJCA contends that PJM’s assertion that it does not have information needed to \ndetermine locational parameters for 15-year term capacity commitments cannot be \nreconciled with PJM’s intention to allocate RBP costs to zones based on their large load \nforecasts. PIOs also argue that PJM’s point that it lacks the necessary information to \ncalculate locational parameters 15 years out is flawed because PJM does have some\nlocational information that it could use, similar to the three-year-forward forecast for the \nRPM. PIOs insist that any locational considerations (even ones with a less certain \nprojection than the three-year forecast of the RPM) will be better than none. AEP \nsimilarly contends that PJM’s claim that it cannot predict future CETO or CETL values \n128 Market Monitor Protest at 7-8, 11. \n129 PIOs Protest at 16, 28, 34; JCA Protest at 36-37. The Market Monitor similarly \nnotes that PJM could require that the generation to serve a data center must be in the \nsame Locational Deliverability Area as the data center. Market Monitor Protest at 11. \nPIOs assert that the risks associated with high Network Upgrade costs are not speculative, \nhighlighting RRI as an example, where 10 of the 51 projects withdrew from the \ninterconnection process. PIOs Protest at 19-20 (citing PJM, Cycle Service Request Status \n(July 2023), https://www.pjm.com/planning/m/cycle-service-request-status); AEP Protest \nat 17."},{"page":37,"startToken":15358,"endToken":15834,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 37 - \nwith precision does not eliminate the need to establish a reasonable relationship between \nthe resources procured and the reliability benefits for which customers are charged.130\nParties similarly express concerns that PJM’s proposal includes no direct market \npower screens or mitigation. JCA argues that the RBP fosters the exercise of seller-side \nmarket power and is unlikely to secure the least-cost combination of resources.131 JCA \nstates that PJM offers no supporting evidence that the resulting procurement price will be \nthe result of true price competition, or that the outcome will reflect the marginal cost of \nthe resources to be procured. JCA states that every resource eligible to offer into the \nRBP can bid to raise prices to the $555/MW-day average price cap regardless of its \nmarginal cost or that of its competitors, allowing the exercise of seller-side market power. \nJCA argues that PJM admits that market power concerns remain because it acknowledges \nbidders are most likely to offer the expected clearing price and not their own marginal \ncost of production. In contrast to PJM’s statements that there is a sufficient number of \npotential suppliers to discipline market power concerns, JCA states that only about 80 of \nthe 397 projects identified in the Charles River Associates Survey Results claim an \nability to achieve commercial operation by the 2028/2029 delivery year and only 3% of \nall projects are under construction.\nJCA and NOVEC question whether PJM has accommodated sufficient \ncompetition. According to NOVEC, the companies with the wherewithal to prepare \noffers on an expedited basis and accept the uncertainty risk are likely to be staffed \nsufficiently to gamble on whatever the RBP rules might turn out to be without detracting \nfrom their established sources of revenue and have significant market share of PJM’s \nexisting generation.132 NOVEC argues that if more time were afforded, more participants \nmight think through ways to offer at lower rates and still be profitable. JCA argues that \nnot allowing commitment terms ending before 2042/2043 excludes resources that can \nenergize in time for the 2028/2029 delivery year but are unwilling or unable to be bound \nthrough the 2042/2043 delivery year. JCA asserts that PJM does not defend the 15-year \ncommitment term as necessary to cure the reliability shortfall or compare the term against \nshorter alternatives, despite the Charles River Associates Survey Results indicating \ninterest from resources in shorter terms.133\nTo expedite new capacity that can address the reliability shortfall, Amazon \nrequests that the Commission direct PJM to provide an accelerated interconnection \n130 JCA Protest at 28-29; PIOs Protest at 23; AEP Protest at 17 n.56. \n131 JCA Protest at 17-22. See also Market Monitor Protest at 13. \n132 NOVEC Protest at 5. See also OCC Protest at 10. \n133 JCA Protest at 14 (citing Charles River Associates Survey Results at 5)."},{"page":38,"startToken":15834,"endToken":16185,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 38 - \nprocess for RBP Resources and resources supported by executed bilateral capacity \narrangements with new large loads.134 DCC encourages continued interconnection and \npermitting reforms.135\niii.\nDetermination \nWe are unpersuaded by arguments that PJM’s filing is unjust and unreasonable \nbecause it lacks locational constraints and direct market power mitigation. First, we find \nthat the proposal’s lack of locational constraints does not render PJM’s overall proposal \nunjust and unreasonable. Specifically, the volume of capacity that PJM will procure \nthrough the RBP auction—up to 6,831 MW—is relatively small compared with total \nexisting supply in PJM (149 GW), so even if RBP Resources are not located in the exact \nsame Locational Deliverability Areas as new loads, the effect of any locational \nconstraints should be limited. Moreover, as PJM explains, the RBP is designed to \naddress the PJM Region’s capacity shortfall, such that it is addressing an effectively \nregion-wide problem.136 PIOs are correct that, depending on where RBP Resources \nchoose to site themselves, significant Network Upgrades could be triggered. But one can \nreasonably assume that RBP Resources will include anticipated Network Upgrade costs \nin their RBP Sell Offers—meaning that RBP Resources that anticipate significant \nNetwork Upgrade costs will be less likely to clear in the RBP auction. \nSecond, we find that the lack of direct market power screens or mitigation for the \nRBP does not render PJM’s overall proposal unjust and reasonable. As PJM explains, in \nthe context of a pay-as-bid structure with a maximum willingness to pay set at $555/MW-\nday, the effectiveness of such measures would be limited. In addition, PJM’s proposed \naverage-price cap of $555/MW-day further disciplines costs by increasing the risk that \nhigh offers do not clear. And as PJM argues, the exercise of market power is unlikely if \neven a portion of the more than 130 GW of supply identified in the Charles River \nAssociates Survey Results decides to participate and drive down prices.137\n134 Amazon Comments at 6. \n135 DCC Comments at 6-8. \n136 Transmittal at 33. \n137 Charles River Associates Survey Results at 5."},{"page":39,"startToken":16185,"endToken":16534,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 39 - \n3.\nTopics for Discussion in Paper Hearing Procedures \na.\nPJM’s RBP Proposal May Be Unjust and Unreasonable \nAbsent Modifications \ni.\nCost Allocation \n(a)\nCost Allocation at the Electric Distributor \nZone/Area Level138\n(1)\nFiling \nPJM proposes to allocate the Initial RBP Target MW to each Electric Distributor \nzone/area using that zone/area’s pro rata share of the difference between the forecasted \nLoad Adjustments139 for the 2026/2027 delivery year and the 2028/2029 delivery year.140\nAn Electric Distributor zone/area’s initial difference in Load Adjustments may then be \nreduced by Qualifying RBP Offset UCAP MW (referred to hereinafter as “offset \ncapacity”), converted to load MW, and opt-outed load, as summarized further below.141\nPJM also proposes to decrement the Initial RBP Target MW by both the amount of \nregionwide offset capacity and the UCAP obligation value of opted-out load to derive the \nFinal RBP Target MW.142 PJM proposes then to allocate the costs of the RBP based on \neach Electric Distributor zone/area’s final assigned share of the Final RBP Target MW, \nwhich shall remain constant throughout the fixed 15-year term. \nPJM argues that the proposed Electric Distributor zone/area cost allocation method \nroughly assigns RBP Charges to the zone/areas with reported new load that is not \n138 The PJM Region is divided into about 20 Electric Distributor-administered \nZones that are further divided into numerous “zone/areas” comprised of LSEs. \n139 As discussed further below, Load Adjustments are “any MW quantity of \nadjustments to summer peak load at the ‘zone/area’ level and summed by Zone as further \ndetailed in PJM Manuals.” PJM, Intra-PJM Tariffs, RAA, art. 1 (Definitions) (48.2.0). \n140 Proposed Tariff, attach. DD, § 18.3 (0.0.0), § 18.3(a). \n141 PJM proposes to divide submitted offset capacity MW by the 2028/2029 BRA \nForecast Pool Requirement “to identify the amount of load that is being served by those \noffset MW.” Transmittal, attach. C (Affidavit of Danielle Croop) ¶ 48 (Croop Aff.). \n142 Proposed Tariff, attach. DD, §18.1 (0.0.0), § 18.1(b)."},{"page":40,"startToken":16534,"endToken":16921,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 40 - \nmatched with new capacity.143 According to PJM, these Electric Distributor zone/areas \nand underlying LSEs can be said to have caused the resource adequacy shortfall reflected \nin the 2028/2029 BRA. PJM therefore contends that applying the method set forth in \nRAA, Schedule 8, with adjustments for offset capacity roughly assigns Electric \nDistributor zone/areas that caused the shortfall with a share of the RBP Charges. \n(2)\nResponsive Pleadings \nParties express numerous concerns with PJM’s proposed cost allocation method \nfor RBP costs at the Electric Distributor zone/area level. Several parties argue that PJM’s \nproposal to fix the cost allocation for 15 years conflicts with PJM’s proposal to base that \ncost allocation on only one snapshot of forecasted load growth.144 AEP contends that \nPJM’s proposal is unreasonable absent some allowance for adjustment to the allocation \nover time.145 Amazon states that PJM’s proposal to base cost responsibility on a single \nsnapshot of forecasted load growth, rather than updating the allocation as load actually \nmaterializes, is inconsistent with cost causation and beneficiary pays principles.146\nAmazon argues that the proposed method is problematic because a capacity allocation \ndetermined before load materializes will begin to diverge from actual cost causation. \nNOVEC asserts that PJM has not explained why this snapshot in time is appropriate \nbeyond references to Schedule 8 of the RAA.147 Vistra argues that although PJM claims \nthat the 15-year contract term will provide financing certainty, it is not clear why the cost \nallocation at the Electric Distributor zone/area level needs to be frozen to accomplish that \ngoal.148 AEP believes that the RBP financial obligations should follow the LSE serving \n143 Transmittal at 103. \n144 ICC and JCA emphasize that by offering only contract terms that terminate in \n2042/2043, the RBP may compound the impact of forecasting errors. ICC Comments at \n4; JCA Protest at 34. JCA asserts that PJM’s only support for the 15-year payout period \nis that it is needed to comply with the NEDC/PJM Governors’ Principles. See also Blue \nRidge Comments at 3-4 (expressing concern that a one-time allocation of costs may \nbecome unjust and unreasonable over the 15-year period). \n145 AEP Protest at 28. \n146 Amazon Comments at 2, 4-5. \n147 NOVEC Protest at 11, 18. \n148 Vistra Protest at 6."},{"page":41,"startToken":16921,"endToken":17294,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 41 - \nthe large load customer whose load growth gives rise to the RBP responsibility, not the \nElectric Distributor for the zone/area in which that customer happens to be located.149\nJCA questions the initial accuracy of PJM’s forecasted load growth, noting that \nPJM’s large load forecasts have fallen by more than half since April, from 14.8 GW to \n6.8 GW.150 According to ICC, even if the regional load forecasts remain roughly \naccurate, failure to accurately forecast the locations where such growth will materialize \nmay result in the wrong zones shouldering the costs.151 Policy Integrity contends that if \nthis is the case, PJM’s proposed RBP cost allocation is unlikely to even be “roughly \ncommensurate” with the participants who receive the benefit of that capacity.152 NOVEC \nargues that the problem with relying on Load Adjustments is that, even if they are “firm,” \nthey are based on economic circumstances that no longer exist. NOVEC believes that the \nRBP will raise the costs of data center loads, which will either prompt marginal data \ncenter projects to withdraw or cause data centers to relocate to areas not assessed RBP \nCharges.153\nTo address the perceived problems caused by a static RBP cost allocation, \nAmazon urges the Commission to require PJM to update the allocation of RBP costs \nperiodically to reflect actual incremental load growth over the RBP commitment period. \nAmazon argues that this would reduce the risk of allocating stranded costs to existing \ncustomers and eliminate the perverse incentive for new large load customers to \nstrategically site in zones initially assigned small obligations.154 ICC maintains that PJM \n149 AEP Protest at 31. \n150 JCA Protest at 12 (citing PJM, Reliability Backstop Procurement Design: \nReliability Backstop CIFP11 (Apr. 2026), https://www.pjm.com/-\n/media/DotCom/committees-groups/cifp-rbp/2026/20260416/20260416-item-05---pjm-\nreliability-backstop-procurement-design---pjm-presentation.pdf; Croop Aff. ¶ 4). \n151 ICC Comments at 4. \n152 Policy Integrity Comments at 19. See also JCA Protest at 5 (arguing that if \nforecasted load fails to materialize, “other customers in the affected zone will be assigned \nthe RBP costs, barring a binding agreement for the large load to cover its stranded \ncosts”). \n153 NOVEC Protest at 18-19. \n154 Amazon Comments at 4-5."},{"page":42,"startToken":17294,"endToken":17668,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 42 - \nshould have proposed a mechanism to moderate any potential forecasting error, such as \ncost reconciliation.155\nNOVEC argues that PJM’s proposed cost allocation method violates the cost \ncausation principle by failing to recognize the structural causes of the capacity shortfall \nbeyond load growth, such as generator retirements due to state policies. NOVEC asserts \nthat many generator retirements were precipitated by the policies of states whose Electric \nDistributors will not be bearing RBP Charges and the RBP Collateral requirement for \nLSEs.156 According to the Market Monitor, the inclusion of all loads in PJM’s initial \nprocurement target (due to Load Adjustments including all types of load) is unduly \ndiscriminatory because non-data-center loads do not present the extraordinary \ncircumstances—large volumes of MW being added quickly—that the RBP should \naddress.157\nNOVEC contends that PJM’s cost allocation method does not adequately account \nfor the market-wide benefits that RBP Resources may provide by lowering prices in the \nRPM Auctions through their $0/MW-day offers.158 NOVEC argues that the RBP’s \ncontract-for-difference settlement structure compounds this mismatch. Noting that RBP \nResources receive RPM revenues that offset their RBP commitment payments, NOVEC \nargues that if the mandatory $0/MW-day offers of RBP Resources contribute to a lower \nRPM clearing price, those resources would receive less RPM revenue and the \ncorresponding RBP settlement obligation would increase. NOVEC maintains that RBP \nbuyers therefore may bear larger RBP Charges while capacity purchasers in the RPM \nbenefit from the lower RPM price. \nParties also fault PJM for not providing a fuller explanation of why and how it \nuses Load Adjustments as the foundation of its cost allocation method.159 EKPC argues \nthat it is unclear whether PJM is properly using the information from Table B9b from the \n2026 PJM Load Forecast to ensure Electric Distributor zone/areas receive correct \n155 ICC Comments at 4. \n156 NOVEC Protest at 9-11 (citing PJM, Energy Transition in PJM: Resource \nRetirements, Replacements & Risks 6-7 (Feb. 2023), https://www.pjm.com/-\n/media/DotCom/library/reports-notices/special-reports/2023/energy-transition-in-pjm-\nresource-retirements-replacements-and-risks.ashx). \n157 Market Monitor Protest at 18. \n158 NOVEC Protest at 15-16. \n159 See, e.g., NOVEC Protest at 18 (arguing that PJM’s Load Adjustment process \nis “somewhat of a black box”)."},{"page":43,"startToken":17668,"endToken":18066,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 43 - \nallocations, given that some Electric Distributor zone/areas cross state lines.160 Equinix \nasks the Commission to direct PJM to provide affected loads with sufficient transparency \ninto the Load Adjustment data underlying RBP cost allocation, subject to appropriate \nconfidentiality protections, together with a process to correct demonstrable errors or \nduplication.161\n(3)\nAnswers \nIn response to protests regarding PJM’s proposed cost allocation method for RBP \ncosts at the Electric Distributor zone/area level, PJM argues that (1) the Commission has \nlong held that relying on snapshots is an acceptable and appropriate method for \nestablishing baselines or targets, (2) the capacity shortfall can be directly attributed to the \nLoad Adjustments submitted to PJM by entities in the Electric Distributor zone/areas that \nwould be allocated RBP cost responsibility, and (3) the target provides certainty to that \nzone/area on the quantity of RBP MW that the loads will be responsible for paying, while \nstill providing the flexibility for RERRAs to update LSE cost allocation during the term \nof such commitment. PJM argues that Load Adjustments need not identify specific non-\njurisdictional loads or be limited to one type of load (e.g., new data center customers) \nwhen the resource adequacy shortfall is caused by all types of loads that comprise the \nsubject Load Adjustments.162\nParties filed answers in response to PJM’s answer. NJBPU is concerned that \nsubstantial discrepancies exist in the inputs each Electric Distributor used to develop their \nLoad Adjustments, and that these discrepancies will result in a discriminatory cost \nallocation outcome.163 NJBPU explains that its staff recently met with Electric \nDistributors to discuss 2027 Load Adjustments, pursuant to a new process established \nunder recent revisions to PJM Manual 19.164 NJPBU maintains that it is now clear that \nthe 2026 Load Adjustments used to determine PJM’s proposed RBP cost allocation \nmethod relied on data with substantially different characteristics across the PJM footprint. \nNJBPU explains that, in New Jersey, while some Electric Distributors reported load \ngrowth only for new large loads of 50 MW and above, other Electric Distributors \n160 EKPC Protest 20. \n161 Equinix Comments at 2. \n162 PJM Answer at 60-61, 64. \n163 NJBPU Answer at 3. \n164 Id. at 4 (citing PJM, Manual 19: Load Forecasting & Analysis, attach. B (June \n30, 2026), https://www.pjm.com/-/media/DotCom/documents/manuals/m19.pdf (adding \nthe RERRA Review requirement))."},{"page":44,"startToken":18066,"endToken":18489,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 44 - \nreported all Load Adjustments with no MW threshold. Furthermore, NJBPU states that \npresentations from PJM’s September 2025 Load Analysis Subcommittee suggest that \nthese inconsistencies could be regional, with the result being that Electric Distributors \nreceive different RBP cost allocations based not on load growth alone, but on their \nchosen characteristics for Load Adjustments. For example, NJBPU notes that \nFirstEnergy’s presentation states it uses loads 50 MW or greater as inputs to the Large \nLoad Adjustment, while Duke Energy states that it reported expansions of 20 MW or \ngreater—and PJM later removed Duke Energy’s Load Adjustment because PJM \ndetermined its economic models would capture the load growth.165 According to NJBPU, \nit is unclear how pervasive these different treatments were because reporting Electric \nDistributors generally did not specify whether they used a MW threshold. NJBPU \ncontends allocating costs using these inputs is thus unduly discriminatory because some \nloads less than 50 MW in one zone/area will take on RBP obligations, while loads of the \nsame size in a different zone/area will not, solely based on whether their Electric \nDistributors included the loads in their Load Adjustments. NJBPU believes that PJM can \nresolve this issue after the RBP is held but before cost allocation by submitting a \ncompliance filing to implement a consistent MW threshold for Load Adjustments.166\nThe Market Monitor argues that PJM’s proposed 6,831 MW procurement target, \nbased on the capacity shortfall recorded for the 2028/2029 BRA, is no longer correct \nbecause of changes in data center loads.167 The Market Monitor states that the data center \nload forecast for the 2028/2029 BRA was based on Load Adjustments received by PJM \nbefore September 5, 2025.168 The Market Monitor asserts that, since then, 4,017 MW of \n165 Id. at 4-5 (citing FirstEnergy, PJM LAS Large Load Adjustment Presentation, \nat 4 (Sept. 2025), https://www.pjm.com/-/media/DotCom/committees-\ngroups/subcommittees/las/2025/20250916/20250916-item-04h---first-energy-large-load-\nrequest.pdf; Duke Energy, Approach to Large Load Adjustments 3 (Sept. 2025), \nhttps://www.pjm.com/-/media/DotCom/committees-\ngroups/subcommittees/las/2025/20250916/20250916-item-04l--duke-large-load-\nrequest.pdf; PJM, Load Adjustment Request Summary for 2026 Load Forecast – \nPreliminary 9 (Nov. 2025), https://www.pjm.com/-/media/DotCom/committees-\ngroups/subcommittees/las/2025/20251124/20251124-item-03---large-load-adjustment-\nrequests-summary.pdf). \n166 Id. at 5-6. \n167 Market Monitor Answer at 15. \n168 Id. at 14-15 (citing PJM, Large Load Adjustment Discussion (Oct. 2025), \nhttps://www.pjm.com/-/media/DotCom/committees-\ngroups/subcommittees/las/2025/20251028/20251028-item-05---large-load-"},{"page":45,"startToken":18489,"endToken":18926,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 45 - \ndata center load, or 42% of the forecasted increase in the data center load between the \n2026/2027 delivery year and 2028/2029 delivery year, have been cancelled or delayed as \nof September 21, 2026.169 The Market Monitor states that of this 4,017 MW, the \nDominion Electric Distributor accounts for 51%, while the AEP-Ohio Electric Distributor \naccounts for 29%. The Market Monitor contends that after accounting for these data \ncenter cancellations and delays, the capacity shortfall for the 2028/2029 BRA would be \nreduced from 6,831 MW to 3,055 MW.170\n(b)\nCost Allocation at the LSE Level \n(1)\nFiling \nPJM proposes that cost allocation to LSEs within an Electric Distributor zone/area \nbe based on the state- and/or RERRA-determined allocation of cleared RBP UCAP MW, \nas reported by each Electric Distributor to PJM.171 PJM thus proposes a new defined \nterm, the RBP Obligation or RBO, to refer to this state- and/or RERRA-determined \nallocation. PJM argues that the RBO permits states and/or RERRAs to rely on their own, \ndisparate definitions of data centers and large loads, and to determine which retail \ncustomers should be allocated RBP Charges.172 According to PJM, its authority over \nwholesale markets does not extend to dictating the allocation of costs to retail load and, \nfor purposes of cost allocation to large loads, each state and/or RERRA may have its own \nadjustments.pdf). \n169 The Market Monitor states that its calculation of 4,017 MW is based on \ntracking of data center project status by Industrial Info Resources \n(https://www.industrialinfo.com) corroborated by publicly available data. Id. at 15 n.29. \nThe Market Monitor explains that it does not have access to project-level data behind \nLoad Adjustments requested by Electric Distributors. The Market Monitor further states \nthat it considered only cancelled and delayed data center projects that were originally \nscheduled to be in service by 2029 as indicated by the Industrial Info Resources tracking \ndata. Regarding its claim that 4,017 MW represents 42% of PJM’s calculated increase in \ndata center load, the Market Monitor states that PJM included 11,993 MW of data center \nload in the 2026/2027 BRA and 21,474 MW in the 2028/2029 BRA. Id. at 15 n.28. The \nMarket Monitor states that the cancelled or delayed data center load of 4,017 MW as of \nSeptember 21, 2026, represents 42% of the 9,481 MW increase (21,474 MW minus \n11,993 MW). \n170 Id. at 18. \n171 Proposed Tariff, attach. DD, § 18.3(b). \n172 Transmittal at 98."},{"page":46,"startToken":18926,"endToken":19420,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 46 - \nmethod, developed in accordance with its unique needs and considerations. If Electric \nDistributors with allocated RBP UCAP MW do not report RBOs by 60 days prior to the \n2028/2029 delivery year, PJM proposes to allocate the RBP Charges for that zone/area to \nall load in the zone/area using each LSE’s ratio share of the Daily Unforced Capacity \nObligation for the zone/area as already determined in RAA, Schedule 8. That is, PJM \nwould allocate the RBP costs assigned to an Electric Distributor zone/area among the \nLSEs in that zone/area in the same manner that it currently allocates RPM costs. \nIn support of its proposed cost allocation method, PJM states that it relies on the \nbest information available to track detailed information about the large loads and the \nvarious LSEs serving such large loads from every state and RERRA in the PJM Region. \nPJM argues that states and RERRAs are in a better position to identify large loads and \nallocate the cost of RBP Charges to the LSEs that serve them.173 PJM asserts that states \nand RERRAs have granular information about large loads within their borders. PJM \nexplains that it has tracked Load Adjustments in zone/areas to the level of granularity that \nis feasible.174 PJM notes that the proposed cost allocation method roughly assigns RBP \nCharges to the Electric Distributor zone/areas with reported new load that is not matched \nwith new capacity. PJM argues that these Electric Distributor zone/areas and LSEs can \nbe said to have caused the resource adequacy shortfall reflected in the 2028/2029 BRA. \nThus, PJM argues, a cost allocation method that provides PJM states and/or RERRAs the \nability to determine the specific RBOs that should be assigned to LSEs within an Electric \nDistributor zone/area, as well as the ability to cost allocate to end-use customers in their \nrespective states in accordance with their laws and policies, supports the NEDC/PJM \nGovernors’ Principles, including the principle that the cost of new capacity should be \nallocated to data centers that have caused the need for additional capacity in the PJM \nRegion. \n(2)\nResponsive Pleadings \nSeveral parties contest PJM’s proposed cost allocation method for RBP costs at \nthe LSE level, including its primary component that depends on RERRAs and states to \nreport RBOs. According to some parties, PJM’s proposal unreasonably relies on state \nlaws that do not exist yet.175 NOVEC contends that PJM’s proposal provides insufficient \n173 Id. at 102-03, 107. \n174 Id. at 103 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 88 (D.C. Cir. \n2014) (“feasibility concerns play a role in approving rates, such that the Commission is \nnot bound to reject any rate mechanism that tracks the cost-causation principle less than \nperfectly.”)). \n175 EKPC Protest at 37 (“PJM cannot make an otherwise insufficient federal rate \ndesign just and reasonable by requiring Electric Distributors, states, or RERRAs to"},{"page":47,"startToken":19420,"endToken":19828,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 47 - \ntime for states to pursue cost allocation methods by the 2028/2029 delivery year.1 JCA \ncalls for a true-up mechanism or abeyance if states do not implement their cost allocation \nmethods in time.176 Amazon argues that state regulators can allocate only the costs that \nPJM has first assigned to the relevant Electric Distributor zone/area, meaning protests \napplicable to that level of cost allocation also apply at the LSE level.177 OCC describes \nvarious risks of cost shifts to consumers if state cost allocation fails.178\nRESA asserts that PJM’s proposal does not explain how RBP costs will be \nassigned to LSEs serving large load customers in retail-choice states as those customers \nmay switch from one LSE to another during the 15-year term.179 AEP similarly argues \nthat PJM’s proposal is lacking in details because it does not explain which party bears \nresponsibility if LSEs decide not to pay their allocated share of RBP Charges, or if their \nload commitments shift over time, or if an LSE disputes their previously allocated share \nof RBP Charges.180\nPA OCA argues that for states to determine the RBO values, they would have to \ndetermine and approve methods for RBO Peak Load Contributions, but that states lack \njurisdiction to do so. PA OCA states that the Commission should exercise its jurisdiction \nover the Transmission Owners’ RBO methodologies, which would be a “natural \nextension” of the Commission’s jurisdiction over the Peak Load Contribution and \nNetwork Service Peak Load methodologies in Tariff Attachment M-2s.181 PJMICC \nsimilarly argues that PJM must require utilities to set forth their RBP-related \nmethodologies in their Tariff Attachment M-2s or some other filing subject to review by \nsupply the missing cost-causation analysis”); EKPC September 18 Answer at 7-8; \nFirstEnergy Protest at 14 (citing N.Y. State Pub. Serv. Comm’n v. FERC, 104 F.4th 886 \n(D.C. Cir. 2024); N.Y. Indep. Sys. Operator, Inc., 183 FERC ¶ 61,130 (2023); Kan. Corp. \nComm’n v. FERC, 881 F.3d 924 (D.C. Cir. 2018)); Movants Protest at 16-17; OCC \nProtest at 7. Ohio FEA and DCC, to the contrary, support allowing states to determine \ncost allocation to large loads. DCC Comments at 6; Ohio FEA Comments at 4. \n176 JCA Protest at 35-36. \n177 Amazon Comments at 4. \n178 OCC Protest at 6-15. \n179 RESA Protest at 9. \n180 AEP Protest at 31. \n181 PA OCA Protest at 11, 14-16, 24."},{"page":48,"startToken":19828,"endToken":20216,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 48 - \nstate commissions. Otherwise, PJMICC argues, “retail cost protections for existing \ncustomers will inevitably fail.”182\nEKPC and SMECO argue that PJM’s proposal improperly expands the role of an \nElectric Distributor in PJM. They contend that PJM’s proposal assigns Electric \nDistributors a series of functions that exceed the metering and data-reporting functions \nElectric Distributors have historically performed for PJM under section 11.3 of the PJM \nOperating Agreement (OA). They assert that these functions include responsibilities \nrelated to not only LSE cost allocation, but also the proposed RBP rules pertaining to \noffset capacity, opt-outs, DER and Demand Resource participation, and collateral \nrequirements.183 SMECO, for example, contends that PJM has called on Electric \nDistributors to develop and provide distribution-impact studies for RBP DER \nAggregation Resources. \nEKPC argues that, pursuant to the OA definition of Electric Distributor, Electric \nDistributors may or may not engage in Commission-jurisdictional activities. Thus, \nEKPC argues, there is no way to know whether they are “public utilities” over which the \nCommission may exercise plenary jurisdiction under Part II of the FPA.184 EKPC states \nthat under FPA section 201(b), the Commission is explicitly precluded from exercising \njurisdiction over “facilities used in local distribution or only for the transmission of \nelectric energy in intrastate commerce.”185 More generally, EKPC argues that the RBP \nproposal is inconsistent with the boundaries of federal and state jurisdiction because it \ninappropriately places obligations on Electric Distributors and states or RERRAs. EKPC \nasserts that determining cost allocations to LSEs and the associated collateral \nrequirements is within the Commission’s primary regulatory authority. EKPC further \nargues that because not all electric distribution companies are PJM Members, an attempt \nto delegate such a role to distribution-level utilities creates jurisdictional overreach by \nbringing such entities into a Commission-jurisdictional ratemaking role. EKPC also \nquestions how PJM’s proposal will be implemented in zones where not all of the load is \nserved by Electric Distributors.186\n182 PJMICC Comments at 6, 8 (also arguing that PJM “must revise its billing \npractices to tag/track RBP-related costs”). \n183 SMECO Comments at 2, 4-7; EKPC Protest at 12, 35-41 (citing EKPC Protest, \nattach. 1 (Affidavit of Adam Bednarczyk)). \n184 EKPC Protest at 40 (citing 16 U.S.C. § 824(e)). \n185 Id. (citing 16 U.S.C. § 824(b)(1)). \n186 Id. at 41-45."},{"page":49,"startToken":20216,"endToken":20620,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 49 - \nVistra argues that PJM’s default proposal to allocate RBP costs to all LSEs, \nregardless of whether they contributed to the current resource adequacy shortfall, is also \nunjust, unreasonable, and unduly discriminatory. Vistra asserts that the resource \nadequacy shortfall is the result of certain LSEs committing to serve more demand than \nthey have supply. According to Vistra, allocating the cost of covering the cumulative \nshortfall to LSEs that had no shortfall, and thus did not contribute to it, would be patently \ninconsistent with cost causation. Vistra further argues that such entities will not \nmeaningfully benefit from RBP because they already procured the capacity they need. \nVistra contends that to the extent those entities enjoy any benefits from the RBP, they are \ntrivial in relation to the costs that RBP promises to impose.187\nODEC similarly argues that using LSEs as the default payer, with no assurance of \nthe level of costs or that those costs will be allocated to large loads, does not adhere to \nprinciples of cost causation.188 PPL asserts that PJM’s backup cost allocation to LSEs \ncould result in LSEs that do not serve large loads receiving these obligations, thereby \nhaving nowhere to assign them except to other customers, which would be inconsistent \nwith the Ratepayer Protection Pledge.189\nEKPC argues that LSEs will be harmed due to the uncertainty of whether they will \nface the RBO cost allocation in which only some LSEs are charged or the default cost \nallocation in which all LSEs are charged. EKPC asserts that PJM thus has failed to \nprovide “clear and transparent procedures” to allow an LSE to determine the amount of \ncosts it may be allocated under the RBP.190 EKPC also notes that under the proposal, \ncosts to LSEs are not fixed over the 15-year payment period, leading to further \nuncertainty. \nSeveral parties advocate for PJM to share RBP cost allocation data with states.191\nAEU asserts that PJM should commit to monitoring and supporting state-level rate design \n187 Vistra Protest at 2-4; see also Blue Ridge Comments at 3-4; EKPC Protest at \n37-38; Movants Protest at 16-17; NCEMC Comments at 20-21; RESA Protest at 5. \n188 ODEC Comments at 4. \n189 PPL Protest at 13. \n190 EKPC Protest at 17-18 (citing Tri-State Generation & Transmission Ass’n, 175 \nFERC ¶ 61,229 (2021)). \n191 See, e.g., DCC Comments at 6; Equinix Comments at 9-11; Google Comments \nat 8."},{"page":50,"startToken":20620,"endToken":21019,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 50 - \nmechanisms and report progress to the Commission and to stakeholders.192 Without both \ninformation sharing and regulatory accountability, PJMICC argues that PJM’s proposal \n“leaves ultimate retail cost allocation rudderless” because states cannot determine retail \nprices “in a vacuum.”193 ICC states that it is unclear how states, particularly retail access \nstates like Illinois, would be able to assign wholesale capacity costs to retail load in the \nmanner PJM proposes and that developing such mechanisms will take time. ICC requests \nthat PJM clarify how states will determine RBOs and whether and how PJM plans to \nassist states in that process.194\n(3)\nPJM Answer \nIn response to protests concerning the role of Electric Distributors in the RBP, \nPJM submits that the RBP relies on Electric Distributors to play an increased reporting \nand coordination role, but not to exceed the scope of their traditional roles. PJM argues \nthat the RBP proposal calls for Electric Distributors to report information and act as a go-\nbetween—roles that are harmonious with the existing role that Electric Distributors have \nplayed in PJM. PJM states that the RBP proposal requires that Electric Distributors only: \n(1) communicate opt-out requests and provide supporting materials to PJM; (2) report \ncapacity offsets and provide supporting evidence to PJM; (3) report state- or RERRA-\ndetermined allocation; (4) report information that feeds the Electric Distributor zone/area \nallocation of the RBP procurement target and LSE daily formula; and (5) provide inputs \nthat impact LSE collateral. Ultimately, PJM states, it is PJM and, where applicable, \nstates and RERRAs—not the Electric Distributors supplying the underlying inputs—that \nwill determine how such inputs inform cost allocation and credit requirements.195\nPJM also argues that SMECO’s claim that PJM has called on Electric Distributors \nto develop and provide distribution-impact studies for RBP DER Aggregation Resources \nmisconstrues the proposed Tariff language, which states that RBP Sell Offers from RBP \nDemand Resources and RBP DER Capacity Aggregation Resources must be \naccompanied by applicable Electric Distributor requirements.196 PJM states that it is not \nimposing requirements on Electric Distributors to develop new or additional studies or \n192 AEU Comments at 27-28. \n193 PJMICC Comments at 2-3, 7-9. \n194 ICC Comments at 5. \n195 PJM Answer at 10-11. \n196 Id. at 11 (citing Proposed Tariff, attach. DD, § 18.5 (0.0.0), §§ 18.5(f)(i)(12), \n18.5(f)(i)(13))."},{"page":51,"startToken":21019,"endToken":21440,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 51 - \nrequirements.197 PJM also clarifies that Electric Distributors perform a reporting or \nadministrative role in the RBP and do not (to the extent that the same entity or subsidiary \nthereof does not occupy another role such as LSE) ultimately bear responsibility for RBP \nCharges. \nResponding to protests regarding the default cost allocation approach, PJM argues \nthat the backup method of allocation is an established, clear, and transparent method. \nPJM states that it lacks the necessary data to assign cost responsibility to the LSEs \nserving the retail load that gave rise to the Load Adjustment in every instance and thus, in \nthe absence of state coordination, it is reasonable to use such a backup method.198\n(c)\nRelated Provisions: Offset Capacity, Opt-\nOuts, and FRR Entities Exclusion \n(1)\nFiling \nTo prevent double procurement, PJM proposes to decrease the Initial RBP Target \nby the amount of offset capacity.199 PJM proposes to credit offset capacity (converted to \nload MW) against an Electric Distributor zone/area’s change in forecasted load between \n2026/2027 and 2028/2029 and then recalculate all the procurement targets under that \nElectric Distributor given that forecast change. Any entity can report offset capacity to \nPJM during the bid submission window, but Electric Distributors are required to provide \nreports and evidence of offset capacity in each of their respective zone/areas. PJM \ndetermines the amount by which offset capacity may reduce the Initial RBP Target based \non the applicable Effective Load Carrying Capability (ELCC) Class Ratings for the \n2028/2029 BRA or, where the relevant resources do not have ELCC Class Ratings, the \nestimated unit-specific UCAP values for such resources. The capacity must not have \npreviously cleared in RPM nor been previously committed in an FRR plan, as of the \nbeginning of the RBP. Offset capacity may be: (1) a new build generation resource, \nincluding new resources that obtain Capacity Interconnection Rights (CIR) transferred \nfrom either deactivated resources or resources that have announced deactivation as of \nApril 10, 2026;200 (2) incremental capacity created by an uprate of existing Generation \n197 Id. at 11-12. \n198 Id. at 69. \n199 Transmittal at 37; Proposed Tariff, attach. DD, § 18.2. \n200 PJM argues that because April 10, 2026 is the day that PJM first posted this \neligibility requirement, such a cutoff date guards against resource owners potentially \ngaming retirements by, for example, entering a deactivation notice after this date only to \nclaim that it is being repowered in advance of the RBP. Transmittal at 41 n.111."},{"page":52,"startToken":21440,"endToken":21863,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 52 - \nCapacity Resources, but only to the extent such incremental capacity is created through \nan increase in such Generation Capacity Resource’s ICAP and increase in CIRs \nassociated with that Generation Capacity Resource; (3) incremental capacity created by \nthe use of Surplus Interconnection Service; (4) repowering of a deactivated generation \nresource that deactivated prior to April 10, 2026; (5) incremental capacity, whether due to \ngreater unforced capacity or a higher level of CIRs, created by an existing Generation \nCapacity Resource’s changing fuel type to a more efficient fuel type; or (6) Planned \nDemand Resource or Planned Distributed Energy Resources (DER) Capacity \nAggregation Resources. Under these rules, Energy Storage Resources are eligible. \nOffset capacity may be supported by signed bilateral contracts for at least five \ndelivery years or by self-supply generation that is in an integrated resource plan with \neither associated generation in the PJM interconnection queue or signed bilateral \ncontracts for at least five delivery years.201 To serve as offset capacity, both signed \nbilateral contracts and self-supply must be supported by documentation of an expected in-\nservice date of no later than June 1, 2032.202 The evidence must also demonstrate that the \nnew capacity is matched with new load. PJM argues that the five-year requirement \nensures capacity is not transitory while not being so lengthy as to undermine the \nflexibility needed for commercial contracting.203\nNew load can provide offset capacity by participating as a Demand Resource or \nDER Capacity Aggregation Resource.204 Such load must offer their full load MW \nquantity into the RPM Auctions starting in the 2028/2029 Second Incremental Auction \nand continuing through the 2032/2033 delivery year. Such new load can subsequently \nreplace UCAP MW provided through such participation by purchasing offset capacity \nthat comes from eligible generation or storage resources. \nThe Initial RBP Target is also decremented where an Electric Distributor elects to \nopt out a zone/area in one of two circumstances.205 First, an opt-out may be requested \nwhere the Electric Distributor’s zone/area has rates that are not regulated by the states \n(e.g., cooperatives or municipal utilities) and is unable to address cost allocation \nassociated with capacity procured in the backstop. PJM states that during the stakeholder \nprocess, cooperatives raised the concern that Electric Distributors in a retail choice state \n201 Proposed Tariff, attach. DD, § 18.2(a). \n202 Proposed Tariff, attach. DD, § 18.2(b). \n203 Transmittal at 39. \n204 Proposed Tariff, attach. DD, § 18.2(c)(iii). \n205 Proposed Tariff, attach. DD, § 18.1(d)."},{"page":53,"startToken":21863,"endToken":22322,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 53 - \nnot regulated by the state and not otherwise serving as the LSE for generation to the load \nwould be forced to have its customers absorb the costs of an “overbuy” if a forecasted \nlarge load failed to materialize. PJM states that unlike a state-regulated, investor-owned \nutility, cooperatives and municipal utilities are not governed by a state regulatory \nauthority that would be responsible for addressing the potential reallocation of RBP costs \nto either other large loads or other zones within the state.206 The opt-out request must \nspecify the associated MW quantity of load in the zone/area that will be opted out of the \nInitial RBP Target and be accompanied by supporting documentation demonstrating an \ninability to address cost allocation associated with capacity procured in the backstop, \nalong with written support for such opt-out from the relevant state governor, RERRA, \nand interconnection customer(s). Second, an Electric Distributor may also request to opt \nout of the RBP for up to the associated MW quantity of load that participates in a peak \nshaving adjustment program codified in state law, where an Electric Distributor’s \nzone/area addresses its capacity needs through such a program.207\nFinally, PJM explains that FRR Entities are excluded from the Initial and Final \nRBP Targets as well as the RBP overall.208 PJM argues that the FRR, by design, is an \nopt-out of RPM, and the RBP is curing a resource adequacy gap from which FRR load \nand FRR capacity are already removed. \n(2)\nResponsive Pleadings \n(i)\nOffset Capacity \nParties contest various aspects of PJM’s proposal to decrease the Initial RBP \nTarget by the amount of offset capacity. JCA and OPSI argue that to be consistent with \nPJM’s proposal to account for offset capacity, the Commission should require PJM to \nreduce the Initial RBP Target also to reflect demand reductions. OPSI states that it views \nthis modification to PJM’s proposal as “critical to protecting other customers.”209 In \nresponse, PJM argues that even if there have been some withdrawals of prospective large \nloads, that forecast nevertheless continues to predict steep load growth. Thus, PJM \n206 Transmittal at 45. \n207 PJM cites one such law. Id. at 45 n.121 (citing N.J. P.L.2026, C.32 (July 7, \n2026) (to be codified at N.J. Rev. Stat. Title 48); NJ A796, Bill Track 50 (last updated \nJuly 7, 2026), https://www.billtrack50.com/billdetail/1954539). \n208 Id. at 31 n.92; Proposed Tariff, attach. DD, § 18.1(c). \n209 JCA Protest at 5, 12, 34; OPSI Comments at 3-4 (arguing that if “new load,” as \ndefined by PJM, terminates an electric service agreement or transmission service \nagreement, PJM should remove that load from its procurement target during the RBP)."},{"page":54,"startToken":22322,"endToken":22738,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 54 - \nargues, it does not need to decrease the RBP procurement target to account for large load \nwithdrawals.210\nPSCWV argues that the proposed offset qualifications are so complex and \ndiscouraging that PJM will likely understate the amount of offset capacity, resulting in an \nexcessive Final RBP Target.211 EKPC contends that PJM’s proposal unfairly socializes \nthe benefit of prudent resource planning by LSEs by allowing Electric Distributors to \nreport offset capacity at only the Electric Distributor zone/area level.212 Equinix argues \nthat it will be unfair if new loads providing offset capacity nevertheless face RBP \nCharges because their states or RERRAs fail to credit loads providing offset capacity.213\nDCC requests that the Commission ensure PJM provides customers with sufficient \ninformation to understand what documentation will be required for offset capacity and \nhow confidential commercial information will be protected.214\nAmazon, FirstEnergy, and Talen argue that PJM should account for contracts \nbetween loads and existing generators if those contracts were executed prior to a certain \ndate. Otherwise, they argue, PJM’s proposal will disrupt existing commercial agreements \nand lead to double payments.215 In response, PJM argues that the purpose of the RBP is \nto procure new capacity to match new loads. PJM argues that this approach helps ensure \nthat capacity offsets and RBP procurements result in a genuine increase in regional \ncapacity rather than simply shifting existing commitments among procurement \nmechanisms. PJM argues that the fact that new load has contracted with an existing \ngeneration resource means that the existing generation resource is no longer serving \nexisting load and the shortfall remains. PJM argues that allowing such existing \ngeneration to offset this target would not contribute to closing the shortfall. PJM also \nasserts that LSEs and large loads should have been on notice that change was coming, \n210 PJM Answer at 25. \n211 PSCWV Comments at 2-3. \n212 EKPC Protest at 15, 28-31; EKPC September 18 Answer at 16-17. \n213 Equinix Comments at 9. See also NCEMC Comments at 3 (arguing that PJM’s \nproposal lacks clarity for LSEs on whether their own costs will be decreased in line with \ndecrements to procurement targets resulting from offset capacity and opt-outs). \n214 DCC Comments at 3-4. \n215 Amazon Comments at 2 (advocating that PJM grandfather in existing contracts \nas of PJM’s filing date); First Energy Protest at 13; Talen Comments at 1 (asking PJM to \nrecognize contracts executed prior to the release of the NEDC/PJM Governors’ Principles \nin January 2026)."},{"page":55,"startToken":22738,"endToken":23137,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 55 - \nand as sophisticated parties, they would have priced and valued in their contractual \nnegotiations the risk of how PJM and the Commission would address the impacts of large \nloads causing the resource adequacy shortfall.216\nDominion and NOVEC note that PJM proposes to credit offset capacity \n(converted to load MW) against an Electric Distributor zone/area’s change in forecasted \nload between 2026/2027 and 2028/2029 instead of against the Electric Distributor \nzone/area’s Initial RBP Target. They argue that this approach leads to double payments \nbecause some supply to serve incremental load was procured in the RPM Auctions. They \nalso note that PJM’s approach effectively socializes offset capacity among all an Electric \nDistributor’s zone/areas rather than targeting only the zone/area providing the offset \ncapacity. As an example, NOVEC explains that although its share of the Initial RBP \nTarget is 1,303 MW, PJM’s proposal would require NOVEC to procure about 1,619 MW \nto fully offset its share. NOVEC argues that is unjust and unreasonable to force RBP \nbuyers to procure an excess of the target MW amount. NOVEC contends that the RBP \nreduces other buyers’ obligations when a single buyer procures offset capacity, which \ncreates a perverse incentive for buyers willing to risk assignment of the RBP Charges to \ndo nothing with the hope that other RBP buyers enter bilateral arrangements and reduce \nthe Final RBP Target.217\nIn response, PJM asserts that it is the Load Adjustments that drive the need for the \nRBP and therefore drive cost allocations to each Electric Distributor zone/area. PJM \ncontends that the fact that the actions of some LSEs or loads may reduce the RBP \nobligations of others is not inherently unjust and unreasonable and, instead, the benefit of \npooled resources is a key feature of being in a Regional Transmission Organization.218\nThe Market Monitor argues that the proposed offset capacity rules allow inferior \nfive-year capacity to displace 15-year capacity. The Market Monitor asserts that PJM’s \nproposal creates strong incentives to provide inferior and shorter-term capacity to meet \nthe 15-year demand. In general, the Market Monitor asserts that PJM does not explain \nwhy offset capacity is held to a weaker standard than RBP Resources given that both are \n216 PJM Answer at 23-24, 65-67. \n217 Dominion Protest at 3, 6-7; NOVEC Protest at 17-18. \n218 PJM Answer at 70, 73."},{"page":56,"startToken":23137,"endToken":23451,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 56 - \nbeing used to satisfy the reliability shortfall.219 The Market Monitor argues that all \ncapacity that addresses the shortfall should be required to meet the same conditions.220\nEquinix, on the other hand, supports the five-year minimum term for the bilateral \ncontracts and bilateral procurement arrangements that may produce offset capacity \nbecause it strikes the right balance between supporting resource adequacy needs and \nmaintaining commercially reasonable structures.221\nVoltus notes that the proposed criteria for offset capacity will count “reactivated” \ngeneration and storage resources against an Electric Distributor’s RBP procurement \ntarget but not reactivated Demand Resource and DER sites, which may unduly \ndiscriminate against demand-side resources.222 Voltus argues that this difference in \ntreatment ignores existing arrangements with Demand Resource sites willing to reactivate \nto contract with large loads. In response, PJM states that it is amenable to updating the \nproposed Tariff, Attachment DD, section 18.2(b)(vi) as follows: \nvi) Planned Demand Resource or Planned DER Capacity \nAggregation Resources, as described in RAA, Schedule 6 and \nSchedule 6.2, where such incremental capacity are not reliant \non locations which previously provided capacity unless such \nprevious locations represents additional capacity resulting \nfrom an investment in new generation or new storage \nresources at that location.223\nVoltus responds that this Tariff language still fails to include reactivated Demand \nResource and DER sites, which will disincentivize large volumes of potential new \ncapacity with near-term availability in the 2027/2028 and 2028/2029 delivery years.224\nCalibrant requests clarification that behind-the-meter generation projects can \nprovide evidence that they are eligible as offset capacity under proposed Tariff, \nAttachment DD, section 18.2(c)(i), which Calibrant states is consistent with PJM’s \n219 Market Monitor Protest at 19-20. \n220 Id. at 21. \n221 Equinix Comments at 13. \n222 Voltus Protest at 3-9. \n223 PJM Answer at 29. \n224 Voltus Answer at 2-6."},{"page":57,"startToken":23451,"endToken":23836,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 57 - \nposition during the stakeholder process.225 In response, PJM reiterates that the eligibility \nrequirements for offset capacity and RBP Resources are not the same. PJM states that to \nthe extent that generation provides capacity meeting the qualifications set forth in either \nproposed Tariff, Attachment DD, section 18.2(c), to provide offset capacity, or proposed \nTariff, Attachment DD, section 18.5, to serve as RBP Resources, that capacity can be \nsaid to contribute to addressing the resource adequacy shortfall.226\nAEU requests clarification of the offset capacity eligibility rules. AEU states that \nproposed Tariff, Attachment DD, section 18.2(c) offers eligibility through three \nevidentiary pathways, but it is unclear whether behind-the-meter generation or storage \nbacking a demand response arrangement may rely on the signed bilateral contract \npathway in section 18.2(c)(i), available on equal terms to front-of-the-meter resources, or \nwhether it is instead confined to the demand response pathway in section 18.2(c)(iii), \nwhich imposes two requirements not applicable under (c)(i): that the resource offset the \nnew load’s full MW quantity rather than a partial share, and that it be in place by the \n2028/2029 Second Incremental Auction or the load purchase replacement offset capacity. \nAEU requests that PJM clarify that behind-the-meter generation and storage backing a \ndemand response arrangement is not categorically confined to the more restrictive \npathway in section 18.2(c)(iii) solely because of its behind-the-meter configuration.227\nAEU argues that the offset capacity provision also raises a threshold eligibility \nquestion. According to AEU, proposed Tariff, Attachment DD, section 18.2(a), appears \nto limit offset capacity eligibility for demand-side resources to Planned Demand \nResponse or Planned DER Capacity Aggregation Resource as described in RAA \nSchedule 6 and Schedule 6.2, potentially excluding reactivations of previously active \nsites and new capacity at existing sites, categories that generation and storage resources \nare expressly permitted to rely on under section 18.2(b). AEU requests that PJM amend \nsection 18.2(a) to align demand-side offset eligibility with the treatment already afforded \nto generation and storage under section 18.2(b), consistent with the stakeholder \nconsensus reached on this issue.228\n225 Calibrant Comments at 1-2. \n226 PJM Answer at 29. \n227 AEU Comments at 17. \n228 Id. at 17-18."},{"page":58,"startToken":23836,"endToken":24202,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 58 - \nConstellation requests that the Commission direct PJM to modify the criteria for \nresources eligible to supply offset capacity to include energy resources that obtain new \nCIRs through an interconnection request.229\nEquinix requests that the Commission direct PJM to publish requirements for \ndemonstrating offset capacity, including the evidence PJM will accept and the process by \nwhich large loads may submit that evidence directly, before the RBP bid submission \nwindow opens.230\nTract argues that PJM should clarify the scope of agreements load can provide as \nevidence of qualifying as “new load” for the purposes of offset capacity. Tract requests \nthat PJM clarify that the undefined terms “electric service agreement” and “transmission \nservice agreement” encompass executed agreements with LSEs or Transmission Owners \nthat evidence a binding commitment by new load to achieve commercial operation by or \nduring the relevant delivery year. In response to Tract, PJM agrees that it is the binding \nnature of contractual agreements that supports a non-speculative commitment to achieve \ncommercial operation within a defined timeframe, not the format in which the contractual \ninstrument has been formalized.231 PJM clarifies that, in the implementation of this \nproposed Tariff provision, it will also consider contractual instruments that PJM deems \nfunctionally equivalent to and serving the same evidentiary purpose as electric and \ntransmission service agreements.232\n(ii)\nOpt-Outs and FRR Exclusion \nRegarding PJM’s proposed RBP opt-outs, parties take various stances. \nFirstEnergy argues that the opt-out targeted at cooperatives and municipal utilities is \nunduly discriminatory because large load in those territories is no less real than large load \nin any other territory, and PJM provides no reasonable basis for treating such loads \ndifferently.233 In response, PJM reiterates that the opt-out was designed to address a \nlimited regulatory gap faced by cooperatives and municipal utilities whose rates are not \nregulated by the states. PJM argues that to the extent that cooperatives and municipal \nutilities’ rates are not governed by a state regulatory authority that would be responsible \n229 Constellation September 8 Answer at 3; Constellation September 21 Answer \nat 2-4. \n230 Equinix Comments at 2, 6. \n231 Tract Protest at 4. \n232 PJM Answer at 28. \n233 FirstEnergy Protest at 19-20."},{"page":59,"startToken":24202,"endToken":24570,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 59 - \nfor addressing the potential reallocation of RBP Costs to either large loads or other \nElectric Distributor zone/areas within the state, there is risk that those cooperatives and \nmunicipal utilities’ customers would absorb the costs of an “overbuy” if a particular large \nload fails to materialize. Thus, PJM argues, the proposed opt-out should appropriately be \nlimited only to those Electric Distributors that are not regulated by the state.234\nODEC notes that its members are rate-regulated and thus not eligible for the opt-\nout. ODEC thus argues for an unrestricted opt-out, asking the Commission to evaluate \nthe opt-out consistent with its broader purpose of protecting smaller utilities from undue \nprocurement risk while preserving flexibility for those entities best positioned to manage \nthat risk.235 In response, PJM states that to the extent that ODEC is the LSE for its \nmember cooperatives and ODEC is not subject to rate regulation by state commissions, \nODEC would qualify as an Electric Distributor that is not subject to regulation by the \nstate and may elect to opt out of the RBP.236 NOVEC counters that a result of PJM’s \nproposal is that one Virginia cooperative, ODEC, can opt out while another Virginia \ncooperative, NOVEC, cannot.237 NOVEC argues that its RBP exposure is not reduced by \nbeing regulated by the state because its customers may still have to absorb the cost of an \noverbuy. \nJCA advocates for an opt-out for any LSE in an Electric Distributor zone/area that \nis allocated RBP Charges that has no large load customers.238 OELC calls for an opt-out \nfor non-data-center large loads that are under 150 MW to protect existing \nmanufacturers.239\nEquinix supports the proposed opt-out for load participating in a state-codified \npeak shaving adjustment program because such load has already addressed its capacity \nneeds.240 Base Power also seeks clarification that to qualify for the peak shaving opt-out, \nthe deadline for any peak shaving adjustment plan submitted pursuant to the requirement \n234 PJM Answer at 30-31. \n235 ODEC Comments at 2, 6-9. \n236 PJM Answer at 31. \n237 NOVEC Answer at 8. \n238 JCA Protest at 35. \n239 OELC Comments at 1. \n240 Equinix Comments at 12."},{"page":60,"startToken":24570,"endToken":24903,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 60 - \nof Tariff, Attachment DD-2 will be September 2027.241 In response, PJM confirms that \npeak shaving adjustment plans for the 2028/2029 Third Incremental Auction can be \nsubmitted as late as September 2027.242\nBase Power seeks clarification from PJM that the peak shaving opt-out is not \ndiscounted and will be one-to-one.243 NJBPU also states PJM should clarify that planned \npeak shaving adjustments can qualify for the opt-out, one-for-one, if they are being \npursued under a requirement codified in state law even if the program’s details are not yet \nfinalized.244 In response, PJM confirms that every MW of peak shaving adjustment, \nconverted into UCAP terms, to opt out of RBP will be used to offset the final RBP \nprocurement target on a one-to-one ratio.245\nRegarding PJM’s proposal to exclude FRR Entities from the RBP, EKPC and \nVistra assert that the proposal is unduly discriminatory because PJM proposes to include \nLSEs that meet their reliability requirements through self-supply, even though such LSEs \nare similarly situated to FRR Entities.246 In response, PJM argues that the scope of RBP \nis to procure capacity for new large loads that did not bring their own capacity, which \ndoes not implicate FRR Entities who by definition must bring new capacity for all new \nloads within their territory or otherwise be subject to FRR Commitment Insufficiency \nCharges.247 EKPC answers that it does not argue that FRR Entities should be subjected \nto the RBP, but rather that PJM fails to explain why similar planning conduct by FRR \nEntities and self-supply LSEs warrants different treatment under the RBP.248\n241 Base Power Comments at 2, 7-8. \n242 PJM Answer at 25-26. \n243 Base Power Comments at 2, 6-7. \n244 NJBPU Comments at 7. \n245 PJM Answer at 26. \n246 EKPC Protest at 45-47; Vistra Protest at 4-5. \n247 PJM Answer at 55-56 (citing PJM, Intra-PJM Tariffs, RAA, art. 1 and Schedule \n8.1D § 7). \n248 EKPC September 18 Answer at 11."},{"page":61,"startToken":24903,"endToken":25321,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 61 - \n(d)\nPJM’s Proposal May Be Unjust and \nUnreasonable \nFor purposes of determining whether a proposed cost allocation method is just and \nreasonable, both “[the Commission] and federal courts have long understood the [FPA’s] \njust-and-reasonable requirement ‘to incorporate a cost-causation principle.’”249 Under \nthe cost causation principle, all Commission-jurisdictional rates and charges must “reflect \nto some degree the costs actually caused by the customer who must pay for them,”250 and \ncosts must be allocated in a manner that is at least roughly commensurate with \nbenefits.251 Compliance with this principle is evaluated by “comparing the costs assessed \nagainst a party to the burdens imposed or benefits drawn by that party.”252 Courts and the \nCommission have acknowledged that adherence to the cost causation principle does not \nrequire that cost allocation methods balance costs and benefits with “exacting \nprecision.”253 Instead, the Commission may approve a given cost allocation framework if \nit “has an articulable and plausible reason to believe that the benefits are at least roughly \ncommensurate with” the assigned costs.254 Consistent with this longstanding precedent, \nwe apply the cost causation principle to evaluate PJM’s proposed method for allocating \nRBP costs. \nAs an initial matter, we find PJM’s proposal to exclude FRR Entities from the \nRBP to be just and reasonable, and thus we do not include it in the list of topics that will \nbe the subject of the paper hearing procedures established in this order. We agree with \nPJM that the FRR Alternative, by design, is an opt-out of RPM and that the RBP \naddresses a resource adequacy gap from which FRR load and FRR capacity are already \n249 Tri-State Generation & Transmission Ass’n v. FERC, 170 F.4th 1254, 1261-62 \n(10th Cir. 2026) (quoting Consol. Edison Co. of N.Y. v. FERC, 45 F.4th 265, 271 (D.C. \nCir. 2022)). \n250 KN Energy Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); see also Ky. \nPub. Serv. Comm’n v. Am. Elec. Power Serv. Corp., 193 FERC ¶ 61,110 (2025) (Ky. \nComm’n). \n251 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d 470, 477 (7th Cir. 2009). \n252 Id. (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 \n(2004)). \n253 Coal. of MISO Transmission Customers, 172 FERC ¶ 61,099 at P 83 (quoting \nMidwest ISO Transmission Owners, 373 F.3d at 1369); see also Ill. Com. Comm’n, 576 \nF.3d at 477. \n254 Ill. Com. Comm’n, 576 F.3d at 477."},{"page":62,"startToken":25321,"endToken":25777,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 62 - \nremoved.255 FRR Entities are required to demonstrate in their FRR Capacity Plan that \nthey have sufficient resources to meet their load obligations. Accordingly, we find that \nFRR Entities have not contributed towards the resource adequacy gap that the RBP will \naddress and, therefore, it is just and reasonable and consistent with the cost causation \nprinciple to exclude FRR Entities from being allocated costs associated with the RBP. \nWe disagree with protesters who argue that PJM’s proposal is unduly discriminatory \nagainst LSEs that meet their reliability requirements through self-supply.256 Specifically, \nwe find that such LSEs are not similarly situated to FRR Entities because, while both \nFRR Entities and LSEs that self-supply own or have contracted for the capacity needed to \nmeet their load obligations, FRR Entities’ load and capacity are removed from RPM, \nwhile the load and self-supplied capacity of such LSEs are not. Moreover, only FRR \nEntities entirely take on the risks of over- or under-supply in their own regions; LSEs that \nself-supply, on the other hand, continue to participate in RPM such that they can procure \nadditional capacity or sell excess capacity in the RPM Auctions. \nWe find that PJM’s proposed opt-out for qualifying cooperatives and municipal \nutilities may be unjust, unreasonable, and unduly discriminatory. PJM states that \nqualifying cooperatives and municipal utilities should be permitted to opt out of the RBP \nbecause they lack state regulatory oversight, and therefore may be unable to assign costs \nto specific large loads. Because cooperatives and municipal utilities serve large loads \nthat are similarly situated to large loads served by other LSEs, allowing an opt‑out may \nbe unduly discriminatory. \nWith respect to cost allocation, as a general matter, we find that PJM’s proposed \nRBP cost allocation method may be unjust and unreasonable. As discussed below, we \nmake this finding because, based on the current record, PJM has not adequately \ndemonstrated that its proposal is just and reasonable and consistent with the cost \ncausation principle. \n255 Transmittal at 31 n.92. \n256 See TranSource, LLC v. PJM Interconnection, L.L.C., 168 FERC ¶ 61,119, at \nP 240 (2019) (“undue discrimination can only occur when two similarly situated \ncustomers are treated differently, and there is no justification for the differing \ntreatment. . . . In other words, a finding of undue discrimination requires a showing that \n(1) two classes of customers are treated differently; and (2) the two classes of customers \nare similarly situated.”.); Solar Energy Indus. Ass’n v. Midcontinent Indep. Sys. \nOperator, Inc., 185 FERC ¶ 61,186, at P 18 (2023) (to “prevail on an undue \ndiscrimination claim,” the party must show that it is similarly situated to others and that \nany different treatment between the similarly situated entities is not justified)."},{"page":63,"startToken":25777,"endToken":26258,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 63 - \nUnder the proposed tariff revisions, PJM “shall allocate the Initial RBP Target \nMW to each Electric Distributor’s zone/area using that zone/area’s pro-rata share of the \ndifference between the forecasted Load Adjustments for the 2026/2027 Delivery Year \nand the 2028/2029 Delivery Year.”257 As a general matter, allocating RBP costs to \nElectric Distributor zone/areas based on a “snapshot” of load growth between 2026/2027 \nand 2028/2029, adjusted down by qualifying offset capacity, may be just and reasonable, \nbecause it reasonably assigns costs to those responsible for the near-term capacity \nshortfall. Thus, such zone/areas benefit from procurement of new resources to fill this \nurgent gap. We generally find that PJM’s proposal to initially assign RBP costs to \nElectric Distributor zone/areas, with the ultimate cost allocation to the LSEs as \ndetermined by the state and/or RERRA and as reported to the Electric Distributor by \nPJM, may be just and reasonable, as it reflects the authority of PJM under the Tariff and \nrespects the authority of the states and/or RERRAs. However, we agree with concerns in \nthe record that relying on Load Adjustments to measure load growth may be inconsistent \nor not reasonably capture forecasted load growth or actual large load growth; thus, PJM’s \nmethod for allocating RBP costs may be unjust and unreasonable. \nSpecifically, based on PJM’s explanation in a previous proceeding of the way in \nwhich it avoids double counting when accounting for Load Adjustments,258 and \ncomments in this record,259 it appears some large loads may never have been accounted \nfor as Load Adjustments because PJM accounted for them when calculating the initial \nload forecast. In short, the delta accounts for net load growth associated with any size or \ntype of load, while excluding any new large loads that PJM knew of and accounted for \nwhen calculating the initial load forecast. As such, the Initial RBP Target MW may only \ncapture a portion of new load growth, potentially leaving out some new large loads. This \ncould lead to the costs imposed on certain entities not being at least roughly \ncommensurate with the benefits they will receive from the procurement. \nAs discussed above, while a cost allocation method need not allocate costs with \n“exacting precision,”260 in order to be just and reasonable it must allocate costs in a \nmanner that is at least roughly commensurate with benefits.261 We find that a cost \n257 Proposed Tariff, attach. DD, § 18.3(a). \n258 PJM Interconnection, L.L.C., 188 FERC ¶ 61,200, at P 21 (2024). \n259 See, e.g., NJBPU Answer at 3-6. \n260 Coal. of MISO Transmission Customers, 172 FERC ¶ 61,099 at P 83 (quoting \nMidwest ISO Transmission Owners, 373 F.3d at 1369); see also Ill. Com. Comm’n, 576 \nF.3d at 477. \n261 Ill. Com. Comm’n, 576 F.3d at 477."},{"page":64,"startToken":26258,"endToken":26712,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 64 - \nallocation method that results in fixed cost assignments over the 15-year RBP \ncommitment period that is based on accurate load forecast information may be just and \nreasonable and consistent with the cost causation principle. However, PJM has not \ndemonstrated that reliance on the Load Adjustment process is just and reasonable. The \nRBP is a one-time procurement of capacity resources to address a shortfall attributable to \nload growth in certain Electric Distributor zone/areas. Allocating RBP costs based on a \nsnapshot of this shortfall over the term of the RBP commitment period may provide \ngreater certainty to the LSEs in the Electric Distributor zone/areas ultimately bearing \nresponsibility for those costs. \nHaving found that PJM’s proposed method for allocating RBP costs among \nElectric Distributor zone/areas may be unjust and unreasonable, and because we are \nordering paper hearing procedures to examine a reasonable cost allocation method, we \ndecline to further address arguments raised in the protests related to PJM’s proposed cost \nallocation method at this time. \n(e)\nPJM’s RBP Proposal May Be Just and \nReasonable if Modified \nHaving found that PJM’s proposed RBP cost allocation method may be unjust and \nunreasonable, and having also initiated an investigation into PJM’s existing Tariff under \nFPA section 206, we now conclude that additional record evidence is needed to \ndetermine whether PJM’s proposed RBP cost allocation method could be just and \nreasonable if modified. We therefore establish paper hearing procedures and direct \nfurther briefing on the issues discussed below. However, we note that the Commission \nencourages PJM to carefully consider the issues we raise in this order and determine the \nmost expeditious path to resolving them. In particular, we encourage PJM to consider \nswiftly submitting a new FPA section 205 filing without delay. \nWhile we find that PJM’s proposal to allocate RBP costs based on its Load \nAdjustment process may be unjust and unreasonable, we note that it may be just and \nreasonable for PJM to allocate RBP costs based on updated load forecast information. \nPJM could base the RBP allocation on the difference between the actual load for \n2026/2027 delivery year in each Electric Distributor zone/area with the most recent \n2028/2029 delivery year load forecast for each Electric Distributor zone/area.262 This \ncould ensure that the load forecast information on which the allocation relies reasonably \ncaptures all forecasted load growth. Such a method for allocating RBP costs among \nElectric Distributor zone/areas may be consistent with the cost causation principle \nbecause it would appropriately assign RBP costs to the Electric Distributor zone/areas \n262 As an alternative to the use of Load Adjustments, PJM could consider using \nother measures of large load growth or potentially aggregate load growth."},{"page":65,"startToken":26712,"endToken":27151,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 65 - \nwith the reported new load that is driving the need for the procurement. Similarly, PJM \nshould employ the most up-to-date load and resource forecasts to inform the Initial RBP \nTarget. \nWe reiterate that we encourage PJM to swiftly submit a new section 205 filing \nwithout delay. We anticipate that the Commission would grant a motion to hold the \nbriefing in this proceeding in abeyance if PJM submitted a new section 205 filing within \n30 days from the date of this order. However, absent such an FPA section 205 filing, \ninitial briefs are due 45 days from the date of this order. Briefs should address whether \nthe above-described method for allocating RBP costs would be just and reasonable. \nWe recognize that the rapid emergence of large loads presents a shared regulatory \nchallenge that implicates both federal and state authority. Under the FPA, the \nCommission oversees rates and practices affecting wholesale service, including PJM’s \nprocurement of capacity through the RBP. However, “states determine how \nCommission-approved rates are collected among the relevant retail consumers along with \nthe rates for state-jurisdictional matters.”263 Specifically, states have authority over how \nthe wholesale costs of providing electricity, including transmission of such electricity to \nthe retail customers, are recovered through retail rates. We are encouraged by the \nNEDC/PJM Governors’ Principles, in which the governors of all 13 PJM states agreed to \n“[u]se all available authorities to ensure that their state public utility commissions design \nrate class structures to ensure that their states’ LSEs allocate their share of the cost to \nprocure new capacity through the [RBP] to new data center loads that have not otherwise \nprocured capacity or agreed to be curtailable.”264 We are also encouraged by the \nexecution of the President’s Ratepayer Protection Pledge, through which data center \ndevelopers have committed to shield retail ratepayers from increased electricity prices.265\nOur partners in the states are more than capable of ensuring that these promises reach \nfruition. While we appreciate and take seriously the issues that PJM’s RBP proposal is \ndesigned to address, as well as the concerns surrounding the unprecedented influx of \nlarge loads more broadly, having only such powers as are given to us by Congress, we \n263 PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, at P 69 (2026); see also\nTransmittal at 106 (quoting the same). \n264 U.S. Department of Energy, Statement of Principles Regarding PJM 2 (Jan. \n2026), https://www.energy.gov/documents/statement-principles-regarding-pjm. \n265 The White House, President Trump’s Ratepayer Protection Pledge Secures \nAmerican AI Dominance, Protects Consumers (July 2026), \nhttps://www.whitehouse.gov/releases/2026/07/president-trumps-ratepayer-protection-\npledge-secures-american-ai-dominance-protects-consumers/."},{"page":66,"startToken":27151,"endToken":27591,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 66 - \nwill not pretend that all of these issues can be solved exclusively by market design in the \nfederal sphere. The PJM states have their own role to play. \nii.\nTransmission Owner Exit Rules \n(a)\nFiling \nPJM proposes to set forth the responsibilities of various parties in the event a \nTransmission Owner exits from PJM. PJM states that establishing these rules in the RBP \nproposal will provide the requisite notice of how RBP commitments will be honored and \nrecognizes that a primary incentive for developers to participate in the RBP is the revenue \ncertainty afforded developers through a 15-year commitment.266 PJM’s proposal is \ndescribed below. \nFirst, if a Transmission Owner exits PJM and committed RBP Resources are \nphysically in that Transmission Owner’s service territory, the Transmission Owner may, \nprior to exiting PJM, enter into a separate agreement with the impacted RBP Resources \nthat would maintain appropriate rates, terms, and conditions of the RBP commitments. If \nthe exiting Transmission Owner does not enter into such an agreement, PJM proposes to \nrequire the exiting Transmission Owner to cover all costs necessary for those RBP \nResources that exceed the Transmission Owner’s withdrawn load to be pseudo-tied back \ninto PJM pursuant to Tariff, Attachment DD, section 5.5A, thus allowing such resources \nto continue providing capacity to serve PJM’s load. PJM states that RBP Resources \nwould be exempted from the electrical distance test to allow for such resources to be \npseudo-tied back into PJM, which will allow such resources to qualify as external \ncapacity resources that can continue to serve PJM loads even if such resources are \nphysically located beyond the usual electric distance requirement. In the event PJM does \nnot elect to retain such RBP Resource or the resource is unable to be pseudo-tied back \ninto PJM, the exiting Transmission Owner would be obligated to pay for the remaining \nterm of the RBP Resource’s commitment on an accelerated basis prior to exiting PJM as \ndetermined through a separate filing with the Commission.267 In the latter two cases, \nPJM states it would pay the collected revenues from the Transmission Owner to the \nimpacted RBP Resources. \nSecond, if a Transmission Owner withdraws from PJM and net load leaves with \nthe Transmission Owner, resulting in stranded committed RBP Resources remaining \nwithin the PJM Region, PJM similarly proposes to allow such exiting Transmission \nOwner, prior to exiting PJM, to enter into agreements that would maintain appropriate \nrates, terms, and conditions and preserve the RBP commitments with the owners of the \n266 Transmittal at 91. \n267 Id. at 92-94; Proposed Tariff, attach. DD, § 18.7 (0.0.0), § 18.7(a)."},{"page":67,"startToken":27591,"endToken":27998,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 67 - \nRBP Resource(s). Absent such an agreement, PJM proposes to require the Transmission \nOwner to pay for all forward obligations associated with the net load that was allocated \nRBP Charges, the exact amount which would be determined through a separate filing \nwith the Commission.268 PJM argues that this would ensure that the remaining load \nwithin the PJM Region will not be stranded with increased costs necessary to pay for the \nremaining term of RBP Resources that are not located within the Transmission Owner’s \nservice territory. PJM states that the revenues collected from the Transmission Owner \nand credited to remaining loads will help offset any cost increases to remaining loads that \nmay be necessary to continue honoring the commitments of RBP Resources remaining in \nthe PJM Region through the rest of the 15-year term.269\nPJM states that establishing these rules in the Tariff now avoids any potential \narguments that changes to cost allocation associated with the RBP Resources after the \ncommitments have already made may be impermissibly retroactive.270 PJM adds that \nthese rules predominately affect RBP Resources and load commitments, particularly in \nrelationship to how they interact with other obligations and assurances provided by \nsuppliers and buyers, and are thus properly addressed in the Tariff, as part of the rules \nconcerning the RBP framework.271\n(b)\nResponsive Pleadings \nPPL and Indicated PJM TOs argue that the Transmission Owner exit provisions \nshould be placed in the CTOA, not the Tariff, as evidenced by the existing CTOA \nrequirements in sections 3.2 and 3.4 governing an exiting Transmission Owner’s \nobligations.272 PPL argues that the Transmission Owner exit provisions predominately \naffect the rights and responsibilities of the PJM Transmission Owners and PJM and \ntherefore should be placed in the CTOA.273 Indicated PJM TOs argue that PJM lacked \n268 Transmittal at 94; Proposed Tariff, attach. DD, § 18.7, § 18.7(b). \n269 Transmittal at 94-95. \n270 Id. at 95-96. \n271 Id. at 96 (citing Duquesne Light Co., 189 FERC ¶ 61,181, at P 55 (2024) \n(citations omitted), order addressing arguments raised on reh’g, 192 FERC ¶ 61,051 \n(2025)). \n272 PPL Protest at 6; Indicated PJM TOs Protest at 6. \n273 PPL Protest at 4, 7 (citing Duquesne Light Co., 189 FERC ¶ 61,181, at P 55 \n(2024); order on reh’g, 192 FERC ¶ 61,051, at P 73 (2025); ISO New Eng. Inc., 106 \nFERC ¶ 61,280 (2004) (internal citations omitted))."},{"page":68,"startToken":27998,"endToken":28419,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 68 - \nauthority to file the Transmission Owner exit provisions because they effectively amend \nthe CTOA. Indicated PJM TOs assert that allowing PJM to alter the CTOA’s substance \nsimply by casting the change as an OATT amendment would effectively provide PJM \nunilateral discretion to amend the CTOA in clear contravention of section 8.5.1 of the \nCTOA, which requires a supporting vote from the Transmission Owners to amend the \nterms of the CTOA. Indicated PJM TOs state that if the Transmission Owner exit \nprovisions are somehow viewed as imposing transmission-related costs, these provisions \nwould fall within the Transmission Owner’s unilateral and exclusive filing rights under \nCTOA section 7.5.1(iv). Indicated PJM TOs add that, at a minimum, the Transmission \nOwner exit provisions relate to or affect transmission-related costs, and thus PJM was \nrequired to, but did not, provide the Transmission Owners with 45-days notice of the \nintended filing pursuant to CTOA section 7.5.1(ii).274\nIn response, PJM argues that the Transmission Owner exit provisions are not \nrequired to be in the CTOA, as they do not relate to or affect transmission-related \ncosts.275\nEKPC and AEP similarly argue that the Transmission Owner exit provisions could \nmeaningfully and unfairly expand the negotiated terms of exit embedded in the CTOA, \nOA, and RAA. AEP states that PJM’s governing documents do not contain an exit fee, \nand Commission precedent confirms that a departing member’s obligation with regard to \ngenerating capacity charges extends only through the last RPM auction in which that \ndeparting member’s load was included.276 AEP and EKPC request that the Commission \nclarify that any acceptance of these exit provisions is limited to these charges and does \nnot undermine existing precedent.277 In response, PJM states that these provisions do not, \nand are not intended to, alter any of the existing responsibilities for Transmission Owners \nthat seek to exit PJM.278\nEKPC and Indicated PJM TOs assert that the Transmission Owner exit provisions \nare inconsistent with Commission precedent and violate the cost causation principle by \nassigning generation- and capacity-related costs to Transmission Owners rather than to \nLSEs. Indicated PJM TOs cite to Duquesne Light Company’s (Duquesne) prior planned \n274 Indicated PJM TOs Protest at 2, 4, 6-8. \n275 PJM Answer at 105-106. \n276 See also AEP Answer at 6. \n277 EKPC September 4 Answer at 3, 6; AEP Protest at 10-11, 20, 26-27 (citing \nDuquesne Light Co., 122 FERC ¶ 61,039, at PP 83, 93 (2008) (Duquesne)). \n278 PJM Answer at 102-103."},{"page":69,"startToken":28419,"endToken":28859,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 69 - \nexit from PJM, under which the Commission found that it was only in the context of \nDuquesne’s role as an LSE pursuant to the RAA that it was responsible for capacity \ncharges. Indicated PJM TOs argue that the Transmission Owner exit provisions violate \nthe cost causation principle because Transmission Owners neither cause the costs of \nprocuring generation capacity over the RBP’s 15-year term (nor the costs of procuring \ngeneration capacity under BRAs), nor do they directly benefit from those costs, while \nLSEs and their customers do.279 PJM responds that these provisions are consistent with \nCommission precedent because RBP commitments are established at the time of the RBP \nand are set for 15 years.280\nEKPC and AEP assert that these rules are inconsistent with the cost causation \nprinciple because they would impose an exit fee that could exceed the RBP Charges \nallocated to a departing transmission owner’s zone. AEP argues that the lack of a \nlocational element in RBP undermines the requirement that a departing transmission \nowner assume responsibility for RBP Resources in its zone/area.281 AEP contends that \nthis requirement could create an undue barrier to the transmission owner’s ability to \nexercise its right to leave PJM and may result in exit charges that are materially greater \nthan the RBP Charges initially allocated to that zone/area. EKPC contends that requiring \nentities that did not cause RBP to bear costs to pseudo-tie generation into PJM is not \nconsistent with cost causation.282\nAEP argues that the exit provisions are unjust and unreasonable for failing to \nprovide the same contract-for-difference structure to departing transmission owners and \ninstead requiring them to fund the full RBP strike price. AEP asserts that requiring a \ndeparting transmission owner and its customers to pay more for RBP Charges (with no \nopportunity to offset the charge) than similarly situated load that stays in PJM is unduly \ndiscriminatory and not tied to the cost causation principle. AEP contends that this would \nbe particularly significant in the event that future load reductions, market changes, or a \ndeparture of an Electric Distributor or transmission owner result in RBP Resources \nbecoming surplus to PJM’s capacity needs. AEP and EKPC requests that the \n279 EKPC September 4 Answer at 5; Indicated PJM TOs Protest at 2, 10 (citing \nDuquesne 122 FERC ¶ 61,039 at P 83); Indicated PJM TOs Answer at 2-3. \n280 PJM Answer at 103 (citing Duquesne 122 FERC ¶ 61,039; Midwest Indep. \nTransmission Sys. Operator, Inc., 124 FERC ¶ 61,219 (2008)). \n281 EKPC September 4 Answer at 4; AEP Protest at 11, 18. \n282 EKPC September 18 Answer at 10-11."},{"page":70,"startToken":28859,"endToken":29334,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 70 - \nCommission require PJM to limit a departing Transmission Owner’s liability to the RBP \nCharges allocated to its zone under PJM’s proposed cost allocation method.283\nIn response, PJM argues that AEP’s arguments fail to appreciate the options \nprovided to an exiting Transmission Owner, which mitigate against the argued \nuncertainty. PJM contends that permitting Transmission Owners to enter into agreements \nwith RBP Resources to negotiate appropriate rates, terms, and conditions will allow the \nTransmission Owner to develop cost recovery provisions that it believes are appropriate. \nPJM states that only in the event that the Transmission Owner opts not to enter into an \nagreement must the Transmission Owner pay forward obligations on an accelerated basis, \nwhich PJM argues is necessary to ensure that the load remaining in PJM is not forced to \nbear the costs of increased RBP Charges. PJM adds that, even in that instance, the \nTransmission Owner would have the opportunity to advocate for further cost recovery \nthrough (1) disputing any allocated costs either prior to the filing or once the filing is \nsubmitted with the Commission, and (2) recovering costs from large loads. In contrast to \nAEP’s assertion that load outside of PJM is similarly situated to load that stays in PJM, \nPJM argues they are not similarly situated because load that leaves PJM would no longer \nbe obligated under the Tariff to pay any applicable RBP Charges while load that remains \nin PJM would be bound by the Tariff and required to pay applicable RBP Charges.284\nAEP, EKPC, and PPL argue that the Transmission Owner exit provisions lack \nsufficient detail and clarity.285 PPL also states that the Transmission Owner exit \nprovisions require that the Transmission Owner enter into agreements with RBP \nResources, but it is unclear how that could be effectuated without coordination between a \nTransmission Owner’s transmission business and generation/marketing business, which \nraises concerns under the Commission’s Standards of Conduct.286 PPL adds that the \nTransmission Owner exit provisions may not apply to every Transmission Owner seeking \n283 AEP Protest at 13-16, 19; EKPC September 4 Answer at 6. \n284 PJM Answer at 99-102 (citing AEP Protest at 14-15). \n285 PPL Protest at 12 (arguing the provisions do not clearly and specifically set \nforth the rates and charges that are to be imposed on an exiting Transmission Owner); \nEKPC September 4 Answer at 5-6 (agreeing with PPL and AEP); AEP Protest at 12-13 \n(asserting that (1) it is not clear what is required to pursue a voluntary agreement under \nsection 18.7(a); (2) PJM does not explain or justify its request to elect not to retain an \nRBP Resource that can be pseudo-tied back to PJM; (3) it is not clear what contract \nwould satisfy section 18.7(b)). \n286 PPL Protest at 7-8 (citing 18 C.F.R. pt. 358 (2025))."},{"page":71,"startToken":29334,"endToken":29737,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 71 - \nto exit PJM because not all Transmission Owners are LSEs that have executed the RAA, \nin which many of the RBP requirements are located. \nPJM responds that it disagrees with protesters that the proposed Tariff language \nlacks specificity. PJM states that there is sufficient detail provided in the Tariff revisions \nto put Transmission Owners on notice of their responsibilities in a manner that also \nprovides for flexibility to meet those obligations, particularly in light of the complexity \nand unknowns involved in a future, hypothetical withdrawal. PJM states that, in the \nevent a Transmission Owner does exit, there will be extensive negotiations that take place \nwith respect to RBP and a variety of other obligations.287 PJM argues that the proposed \nTariff language in Attachment DD, sections 18.7(a) and 18.7(b) is sufficiently clear that \nthe purpose of such agreements is to ensure that the exiting Transmission Owner \npreserves the RBP commitments with the owners of RBP Resources.288 With respect to \nconcerns that PJM may elect to retain an RBP Resource as a capacity resource, PJM \ncontends that it must retain the discretion necessary to ensure resource adequacy and \nreliability, including the ability to consider the topology of the transmission system at the \ntime of the desired exit. With respect to arguments concerning the requisite Commission \nfiling and costs, PJM argues that final cost determinations are appropriately decided at \nthe time of the Transmission Owner’s exit because it is impossible to determine what \nthose circumstances will be. In response, AEP argues that PJM’s answer is unresponsive \nto its concerns and would ultimately afford PJM considerable discretion over a \nTransmission Owner’s ability to withdraw.289\nPJM also disputes that the proposed Tariff revisions violate the separation of \nfunctions requirements of the Commission. PJM states that the proposed requirements \nare merely intended to honor obligations that would have pre-existed the exit of a \nTransmission Owner from PJM. PJM adds that activity that may otherwise violate \nseparation of functions is permissible, pursuant to 18 C.F.R. § §358.2(d), § 358.1(d) \n(2025), respectively, where ordered by the Commission or where the Commission has \ngranted waiver of such requirements.290\n287 PJM Answer at 95-96. \n288 Id. (citing PJM, Intra-PJM Tariffs, ATTACHMENT DD.18.7, \nATTACHMENT DD.18.7 Exiting Transmission Owner RBP Obligation (0.0.0)). \n289 AEP Answer at 4-5. \n290 Id. at 106-107."},{"page":72,"startToken":29737,"endToken":30129,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 72 - \nEKPC and PPL argue that the Commission need not address this issue \npreemptively, particularly given the absence of any pending withdrawal requests and \nPJM’s own acknowledgement that the possibility of this contingency is “remote.”291\n(c)\nPJM’s Proposal May Be Unjust and \nUnreasonable \nWe find that, as proposed, the Transmission Owner exit provisions may be unjust \nand unreasonable. \nAs protesters note, the Commission has previously found that it is just and \nreasonable to impose generation capacity costs on LSEs located within an exiting \nTransmission Owner’s zone.292 In Duquesne, the Commission assessed a withdrawing \nLSE’s RPM obligations and noted that “[u]nder RPM, PJM is responsible for procuring \ncapacity on behalf of LSEs in each zone three years in advance based on the auction \nresults, and PJM’s obligation to pay the generators is fixed at the time of the auction.”293\nThe Commission stated that “Duquesne understood that PJM was procuring capacity on \nits behalf and therefore should be obligated to pay for that capacity.”294 Under its RBP \nproposal, PJM similarly proposes to procure capacity through the RBP on behalf of \nLSEs, establish obligations to pay RBP Resources at the time of the procurement, and \nlater allocate those costs to LSEs. PJM fails to explain why Transmission Owners—who \nare not the buyers for which PJM procures capacity under the RBP—should be \nresponsible for RBP Charges. \nBased on the current record, it appears that the proposed Transmission Owner exit \nprovisions may be inconsistent with the cost causation principle because they do not \nassign costs to the entities that cause the costs and benefit from the capacity procurement \nunder the RBP, i.e., LSEs. As explained in Section IV.B.3.a.i(d) above, under \nthe cost causation principle, all Commission-jurisdictional rates and charges must “reflect \nto some degree the costs actually caused by the customer who must pay for them,”295 and \n291 PPL Protest at 10 (citing Transmittal at 91 (internal citations omitted)); EKPC \nSeptember 4 Answer at 7. \n292 Duquesne 122 FERC ¶ 61,039 at PP 89-94 (2008). See Indicated PJM TOs \nProtest at 8-10; EKPC September 4 Answer at 5. \n293 Duquesne, 122 FERC ¶ 61,039 at P 89. \n294 Id.\n295 KN Energy Inc. v. FERC, 968 F.2d at 1300; see also Ky. Comm’n, 193 FERC \n¶ 61,110."},{"page":73,"startToken":30129,"endToken":30570,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 73 - \ncosts must be allocated in a manner that is at least roughly commensurate with \nbenefits.296 Here, it appears that PJM has not demonstrated that the proposed obligations \nand “exit fees” associated with RBP costs—which PJM proposes to impose on the exiting \nTransmission Owner—reflect the benefits that the RBP will provide. PJM’s RBP \nproposal is necessary to address capacity shortfalls in the PJM Region, and the \nbeneficiaries of the RBP are the LSEs on whose behalf PJM will procure capacity \nthrough the RBP. Therefore, we find that PJM’s proposed exit provisions may be unjust \nand unreasonable because they would assess RBP Charges to exiting Transmission \nOwners, rather than the LSEs in the relevant Transmission Owner’s zone. \nHowever, we disagree with protesters that establishing exit provisions in the Tariff \nwould unnecessarily constrain the parties involved in effectuating a Transmission \nOwner’s withdrawal from PJM. As PJM states, the cost obligations will be \n“appropriately decided at the time of Transmission Owner’s exit and subject to \nCommission approval.”297\n(d)\nPJM’s RBP Proposal May Be Just and \nReasonable if Modified \nAs a general matter, we recognize that it may be just and reasonable to have \nprovisions to protect against cost shifts should a Transmission Owner exit PJM during the \nRBP term (i.e., before the end of the 2042/2043 delivery year). As discussed above, the \nCommission has found that a withdrawing LSE’s obligations under the RAA and \nAttachment DD of the Tariff may include capacity costs.298 Similar to the costs of \ncapacity that PJM procures through its RPM Auctions, PJM here proposes to allocate the \ncosts of procuring capacity through the RBP to LSEs. Therefore, a just and reasonable \napproach could require LSEs in an exiting Transmission Owner’s zone to pay RBP exit \nfees commensurate with their cost allocation under the RBP, to prevent cost shifts to \nother LSEs in the PJM Region. As PJM proposes, exit provisions could still leave \nflexibility for LSEs to enter into agreements with RBP Resources (which they may need \nto serve their load) or pay to pseudo-tie RBP Resources located within the exiting \nTransmission Owner’s zone back into PJM. \nAs discussed elsewhere, we conclude that additional record evidence is needed to \ndetermine a just and reasonable approach to preventing RBP cost shifts should a \nTransmission Owner exit PJM before the end of the 2042/2043 delivery year (i.e., the \ncompletion of the term of RBP Resources’ commitments). Among other topics, the \n296 See, e.g., Ill. Com. Comm’n, 576 F.3d at 477. \n297 PJM Answer at 98. \n298 Duquesne, 122 FERC ¶ 61,039 at PP 86, 90-91."},{"page":74,"startToken":30570,"endToken":30981,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 74 - \nCommission directs further briefing on whether (1) it would be appropriate for LSEs in \nan exiting Transmission Owner’s zone to be responsible for RBP exit charges, rather than \nthe Transmission Owner, and (2) it would be just and reasonable to assign LSEs RBP exit \ncharges based on the cost of capacity that PJM procures through the RBP on behalf of \nLSEs in a Transmission Owner’s zone, i.e., the LSE’s cost allocation under the RBP. \niii.\nLSE Collateral Requirement \n(a)\nFiling \nPJM proposes to require both RBP Sellers and buyers of RBP UCAP MW (i.e., \nLSEs) to provide collateral.299 The collateral for RBP Sellers, required to be posted at the \ntime of the auction, reflects three years of RBP UCAP MW shortfall charges for that \nresource. PJM returns the collateral when an RBP Resource no longer gives rise to credit \nexposure (e.g., after the resource fails to clear). The RBP collateral requirement for LSEs \nis the product of the RBP Credit Rate and the total RBP MW committed. PJM explains \nthat the initial RBP Credit Rate of $1.5 million ensures that PJM holds sufficient \ncollateral to cover about 50% of the notional value of all RBP commitments.300 PJM \nproposes to require that LSEs post collateral 45 days before the first delivery year in \nwhich RBP Resources are expected to be in service (i.e., 2028/2029), and that the \ncollateral be returned as financial exposure lessens. Citing elevated risks in the current \nmarketplace, PJM also proposes strict criteria for acceptable collateral. PJM states that, \n“like the credit requirements imposed on inherently riskier Financial Transmission \nRights,” sellers and buyers of RBP UCAP MW are limited to providing RBP Collateral \nin the form of either a cash deposit or Letter of Credit.\nIf an LSE defaults and fails to pay an RBP Charge, the defaulted amount is \nreallocated to all remaining LSEs responsible for paying RBP Charges based on their pro \nrata share of the total RBP Charges for all such LSEs.301 Such amounts may be offset by \nthe RBP Collateral posted by the defaulting LSE. If an RBP Resource defaults on \npayment of RBP shortfall charges, the corresponding credits are not allocated to the LSEs \nthat would otherwise receive them.302\n299 Proposed Tariff, attach. DD, § 18.8. \n300 Transmittal at 116, 109-110, 120. \n301 Proposed Tariff, attach. DD, § 18.9(a). \n302 Proposed Tariff, attach. DD, § 18.9(b)."},{"page":75,"startToken":30981,"endToken":31380,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 75 - \n(b)\nResponsive Pleadings \nParties contest both the proposed RBP Collateral requirement for LSEs and the \nproposed criteria for acceptable collateral. FirstEnergy, for example, faults PJM’s \nproposal for several reasons, arguing that PJM’s filing lacks the support typically \nprovided for credit requirements. FirstEnergy also faults PJM’s proposal for assuming all \nclasses of LSEs present the same credit risk, regardless of whether they have regulated \ncost recovery. FirstEnergy contends that the proposal is also unduly discriminatory \nbecause under similar Public Utility Regulatory Policies Act contracts, the purchasing \nentities generally have been subject to low or no collateral requirements because of their \nability to recover costs from retail customers.303\nEKPC argues that PJM has not linked the RBP collateral requirement to exposure, \nas evidenced by (1) the timing gap between when the exposure is identified and when the \ncollateral is required and (2) the misalignment between the buyer collateral requirement \nand the seller collateral requirement.304 EKPC contends that PJM’s proposal would result \nin the same obligation being collateralized twice, once under RBP and once under \nAttachment Q of its existing Tariff. EKPC argues that it is also unjust and unreasonable \nto require LSEs to post collateral prior to the finalization of the cost allocation because it \ndoes not provide LSEs with sufficient transparency and time to challenge the \nobligation.305 EKPC asserts that it is not just and reasonable to concentrate the collateral \nrequirements among LSEs that receive RBOs because this creates system liquidity risk.306\nSMECO notes that LSEs could have as few as 15 days from the time they learn \ntheir final collateral requirement to the deadline to post that collateral.307 This is the case \nbecause the deadline for Electric Distributors to report RBO allocations is 60 days before \nthe delivery year, while the collateral deadline is 45 days before the same delivery year. \nEquinix argues that the RBP Collateral requirement for LSEs is not just and \nreasonable for three reasons. First, Equinix asserts that the collateral requirements are \n303 FirstEnergy Protest at 8-9. \n304 EKPC Protest at 22-23 (citing NOVEC Protest, attach. 2 (Affidavit of Carl F. \nCoscia) ¶¶ 203, 204 (Coscia Aff.)). \n305 Id. at 24. \n306 Id. at 27. \n307 SMECO Comments at 7; see also Constellation Protest at 16 (“That [15-day] \nperiod is not reasonably practicable and creates an unnecessary risk of credit default and \nresulting cost reallocation.”)."},{"page":76,"startToken":31380,"endToken":31836,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 76 - \ndisproportionate and inconsistent because sellers have the most control over risks of \ndevelopment and non-performance but have lower collateral requirements than buyers. \nSecond, Equinix disagrees with PJM that RBP exposure is analogous to FTR exposure \nbecause the latter is volatile while RBP Charges are fixed in advance, which is similar to \nthe risk PJM manages under Attachment Q of its existing Tariff. Third, Equinix argues \nthat the collateral requirement does not protect ratepayers because it will require LSEs to \nfinance the posting of the collateral, which will materially raise rates. Equinix requests \nthat the Commission modify the proposed buyer-side RBP Collateral provisions so that \ncollateral is calibrated to reasonably foreseeable forward exposure and the forms of credit \nsupport available under Attachment Q are permitted.308\nNOVEC argues that its highest possible collateral requirement, estimated to be \nabout $1.95 billion, would exceed NOVEC’s total assets and disrupt NOVEC’s ordinary \nbusiness operations. NOVEC adds that it is uncertain whether it would even be able to \nsecure $2 billion in collateral. NOVEC argues that PJM’s proposal to require the \ncollateral obligation of the buyers to span the entire 15-year period is not necessary, as \nthe risk could be significantly mitigated by a shorter period, such as three years. NOVEC \ncontends that the most significant obstacle to NOVEC fulfilling its RBP obligations is the \nsize of the RBP collateral obligation itself and not the RBP Charges. NOVEC notes that \nPJM’s proposal limits the RBP Sellers’ collateral obligation to three years to avoid \nmaking the collateral requirement “onerous.”309\nNOVEC and Constellation also take issue with the assumptions PJM makes when \ncalculating the initial RBP Credit Rate of $1.5 million.310 NOVEC and Constellation \nargue that PJM’s calculation assumes that RBP buyers have to collateralize the entire \n$555/MW-day, when the RBP Charges will be the RBP clearing-price average (which \ncan be less than $555/MW-day) net of revenues from the capacity auction.311 EKPC and \nConstellation aver that PJM has sized collateral as though load owed the full contract \nprice, when the Tariff obligates load to pay only a difference between two prices under \n308 Equinix Comments at 2,6, 15-16; see also SMECO Comments at 2, 8 (claiming \nthat the LSEs’ collateral requirement is 14.5 times the size of the requirement for sellers). \n309 NOVEC Protest at 20 (citing NOVEC Protest, attach. (Affidavit of Wilbur \nRollins) at 2-3). See also EKPC Protest at 13 (arguing that requiring so much collateral \nat once creates a systemic liquidity risk). \n310 Id. at 21 (citing Coscia Aff. ¶¶ 38, 46); Constellation September 8 Answer at 5-\n6. \n311 NOVEC Protest at 21; Constellation September 8 Answer at 6-7. See also\nEKPC Protest at 25."},{"page":77,"startToken":31836,"endToken":32321,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 77 - \nthe contract for differences approach.312 Effectively, NOVEC argues, RBP buyers are \nproviding collateral to ensure that everyone in PJM pays the capacity costs associated \nwith the RBP Resources. NOVEC notes that RBP buyers themselves already provide \nPJM collateral to ensure that they pay their capacity rates under Attachment Q, and so do \nall other capacity buyers.313 NOVEC argues that PJM is thus requiring duplicative \ncollateral. Constellation also expresses concerns that (1) the credit rate relies on 15 years \nof gross contract value rather than the net RBP Charges that LSEs will be billed; (2) the \nTariff does not identify the time needed to draw collateral and reallocate any residual \ndefault, or the stress assumptions used to estimate net exposure; (3) it applies the same \n$1.5 million/MW base rate without explaining why credit quality may increase—but \nnever reduce—the base requirement; and (4) the Tariff establishes no mandatory \nrecalculation schedule, prescribed inputs, or objective collateral-release standard.314\nNOVEC further argues that the proposed Tariff provision is ambiguous as to when \nthe collateral obligation will be reduced and does not appear to properly reduce it over \ntime. NOVEC notes that according to the proposed Tariff provision, “the RBP Credit \nRate shall equal $1.5 million, as may be reduced, for reasons including a change in the \ntotal committed RBP UCAP MW, when total posted RBP Collateral is greater than the \ntotal remaining RBP Charges obligations, over time by the Office of the Interconnection \nto an amount sufficient to cover the total existing RBP Charges obligations.” NOVEC \nargues that PJM should not have the discretion to determine whether RBP buyers should \nbe required to post more collateral than the total existing RBP obligations, especially \ngiven that the calculation already overstates the likely RBP Charges. NOVEC further \nargues that there are too few circumstances in which the collateral obligation is reduced. \nAccording to NOVEC, if PJM believes that 50% of the total payment obligations at the \nstart of the 15-year term is sufficient, then the same percentage of the total remaining \npayment obligations should be the cap for each year.315\nAEP asks the Commission to direct PJM to clarify that collateral obligations attach \nonly to LSEs allocated responsibility for RBP Charges, not to Electric Distributors acting \nsolely in an administrative or delivery-service role. AEP argues that this clarification \nwould be consistent with PJM’s statement that RBP Buyer collateral is intended to \nmitigate the risk of non-payment of RBP Charges and that only LSEs allocated \n312 EKPC Protest at 25; Constellation September 8 Answer at 6-7. \n313 NOVEC Protest at 21 (citing Coscia Aff. ¶ 26). \n314 Constellation September 8 Answer at 6. \n315 NOVEC Protest at 22, 23 (citing Proposed Tariff, § 18.8(b)(i)(A) (emphasis \nadded)). See also FirstEnergy Protest at 9 (criticizing PJM’s proposal to retain absolute \ndiscretion on how quickly it returns excess collateral)."},{"page":78,"startToken":32321,"endToken":32680,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 78 - \nresponsibility for RBP Charges generally will have a credit requirement. AEP further \nargues it would be inconsistent with the cost causation principle to improperly shift credit \nrisk from the entities serving and benefiting from the load to an Electric Distributor that \nneither controls generation supply decisions nor receives the revenues associated with \nserving that load.316\nPPL states that it understands that if there are no RBOs reported to PJM for an \nElectric Distributor zone/area with RBP UCAP MW assigned, or if there are “stranded” \nRBOs, then the credit requirements will move to all LSEs in the zone/area based on Peak \nLoad Contributions. Presumably, PPL continues, once credit requirements are assigned \nbased on Peak Load Contributions, RBP Charges will also flow to those LSEs. EKPC \nand PPL are concerned that this scenario could result in LSEs that do not serve large \nloads receiving these obligations, thereby having nowhere to assign them except to other \ncustomers.317 EKPC, ODEC, and PPL request that PJM clarify that if an LSE defaults \nand fails to pay an RBP Charge, whether the defaulted amount will be allocated to all \nremaining LSEs in the Electric Distributer zone/area or to all LSEs in the PJM Region.318\nConstellation recommends that large load customers be permitted to post collateral \nfor the responsible LSE to avoid unnecessary intermediation through the LSE and \nduplicative credit postings.319 Constellation states that the record is not sufficiently \ndeveloped to prescribe a durable collateral methodology and requests that the \nCommission establish an expedited paper hearing on the matter.320\n(c)\nAnswers \nPJM argues that imposing a credit requirement for the purpose of ensuring only \nthose entities assigned cost responsibility for RBP Resources bear the burden of such \ncosts protects those LSEs not allocated cost responsibility for RBP Resources from \nhaving to pay for such resources.321\n316 AEP Protest at 33-34. \n317 EKPC Protest at 28; PPL Protest at 13. \n318 EKPC September 18 Answer at 12, 16; PPL Protest at 13; ODEC Comments at \n10. \n319 Constellation September 8 Answer at 8. \n320 Id. at 9-10. \n321 PJM Answer at 74-75."},{"page":79,"startToken":32680,"endToken":33065,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 79 - \nIn response to protesters’ claims that the proposed LSE collateral requirement is \nduplicative of exiting PJM credit rules, PJM argues that its existing requirements (i.e., \nPeak Market Activity collateral) serve a different purpose and tracks different types of \nfinancial exposure than the proposed RBP credit requirement.322 PJM states that the Peak \nMarket Activity metric manages immediate, rolling operational risk from daily \ntransactions based upon a rolling, backward-looking billing history, and to the extent an \nLSE defaults on its obligations, the provider of last resort for that load becomes \nresponsible on a going-forward basis. In contrast, PJM states that the proposed RBP \ncredit requirement is to cover forward-looking risk over a long-term, up-to-15-year \ncommitment to sellers. PJM also argues that an LSE’s obligation to pay RBP Charges \nshould not be shunted to a provider of last resort because the large load driving the need \nfor RBP should bear these costs. \nIn response, NOVEC maintains PJM’s proposal does require suppliers to provide \nduplicative collateral because PJM proposes to determine RBP collateral obligations as if \nsuppliers were paying the entire RBP Charge—which means suppliers are providing \ncollateral for the cost of capacity of their RBP MW and providing collateral for the RBP \nclearing price, and not just for the difference between the RBP price and the capacity \nclearing price.323\nRegarding protests that the credit requirements should be tailored to the credit risk \npresented by specific LSEs, PJM states that it looked at the forward obligation to the RBP \nResources instead of individual LSE’s creditworthiness because (1) it better safeguards \nthe payment and reduces exposure in case of default, (2) it allows for a uniform credit \nrate applicable to each allocated MW, which ensures non-discriminatory requirements for \nall LSEs, and (3) creditworthiness of individual LSEs may change considerably during a \n15-year term.324\nIn response, NOVEC argues that PJM overstates the risk of declining \ncreditworthiness because the RBP Charges that NOVEC could be responsible for \nrepresent, in any given year, a tiny fraction of the collateral PJM would require NOVEC \nto post.325 NOVEC therefore argues that the greatest threat to NOVEC’s credit rating is \nPJM’s own RBP collateral requirement. \n322 Id. at 78. \n323 NOVEC Answer at 16-17. \n324 PJM Answer at 80-81. \n325 NOVEC Answer at 18."},{"page":80,"startToken":33065,"endToken":33527,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 80 - \nIn response to protesters’ claims that the credit requirements are excessive, PJM \nargues that the credit requirements are properly tailored to mitigate the risk associated \nwith RBP commitments throughout the up to 15-year RBP commitment term and \ntherefore is derived from the measured forward exposure of the RBP Charges. PJM \nasserts its approach is consistent with Commission policy because it reasonably balances \nprotecting PJM’s members against the risk of default and appropriately correlating the \ncredit requirement with the risk level.326 PJM adds that it limited the forms of collateral \nto letters of credit and cash because it determined there would likely not be sufficient \nunsecured credit available from these LSEs to cover the up-to-15-year forward credit \nobligation. PJM argues that the initial RBP Credit Rate of $1.5 million per RBP UCAP \nMW is just and reasonable and supported because it is keyed to a potential outcome of \nthe RBP, the maximum MW-weighted average of the levelized procurement cost of all \nselected RBP Sell Offers of $555/MW-day, and represents about 50% of the notational \ncontract value at that price.327 PJM contends that this represents approximately 50% of a \nquantifiable potential contractual exposure, rather than full collateralization, and can \ndecline as the remaining exposure declines, which undermines claims that the amount is \nexcessive or insufficiently correlated to credit risk. PJM argues that protesters ignore the \nfact that standard business practices for LSEs signing up new large loads include \nrequiring collateral.328\nPJM clarifies that the LSE collateral requirement for a delivery year is based only \non RBP UCAP MW committed for that delivery year and that “no collateral would be \nrequired for RBP Resources [that] are not in service for that Delivery Year, and no RBP \nCharges would be assessed.”329 In response, NOVEC argues that PJM’s interpretation \nrelies on the meaning of the term “committed” used in proposed Tariff, section \n326 PJM Answer at 84 (citing PJM Interconnection, L.L.C., 186 FERC ¶ 61,055, at \nPP 27-28 (2024) (internal citation omitted)). \n327 Id. at 88. \n328 Id. at 88-92. PPL responds that PJM’s reliance on PPL’s Rate Schedule LP-6 \nas an example in its answer is misplaced and inaccurate. PPL states that this rate \nschedule relates only to its role as an Electric Distribution Company, not an LSE, and \ndoes not relate to PPL’s role or obligations as an LSE nor any security or collateral that \nmay be required to satisfy RBP credit obligations. PPL Answer at 2-3. NOVEC \nsimilarly argues that PJM’s assertion that NOVEC could use its existing collateral \nobligations with its customers is immaterial to the question of whether the proposed RBP \ncollateral requirements are just and reasonable. NOVEC Answer at 20. \n329 PJM Answer at 78 n.234."},{"page":81,"startToken":33527,"endToken":33925,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 81 - \n18.8(b)(i)(A).330 NOVEC points out that proposed section 18.6(e) permits a resource to \nremain “committed” for up to three delivery years, and proposed section 18.8(b)(i)(A) \ndoes not have an “in-service” limitation, creating the risk that NOVEC could post \ncollateral for an RBP Resource that does not operate during those three delivery years. \nNOVEC asks the Commission to require PJM to revise this section to state that LSEs \nwith RBP obligations will not be required to post collateral for RBP Resources that are \nnot in service. \nPJM states that, while it has proposed a just and reasonable approach to \ndetermining the proper buyer-side LSE RBP credit requirement, it also consents to a \nmodified approach where the credit rate is keyed to the actual MW-weighted average of \nthe levelized procurement cost of all selected RBP Sell Offers that results from the RBP \nand not the maximum of such value.331 PJM states that it would consent to the \nCommission resolving the applicable buyer-side LSE RBP Credit Rate through additional \nprocedures.332\n(d)\nPJM’s Proposal May Be Unjust and \nUnreasonable \nFirst, although it is related to the broader topic of RBP Collateral, we find PJM’s \nproposed collateral requirements for RBP Sellers just and reasonable, and thus we do not \ninclude that aspect of the proposal in the list of topics that will be the subject of the paper \nhearing procedures established in this order. Specifically, PJM’s proposed collateral \nrequirements for RBP Sellers are just and reasonable because they will reduce the risks to \nPJM markets associated with non-payment of RBP Shortfall Charges without posing an \nunreasonable barrier to market participation. \nHowever, we find that the proposed RBP Collateral requirement for LSEs (i.e., \nLSE Collateral requirement) may be unjust and unreasonable. \n330 NOVEC Answer at 21. \n331 PJM Answer at 92-93 (citing NOVEC Protest at 22). \n332 Constellation states that it supports PJM’s proposal to resolve the credit and \ncollateral issues through additional procedures. Constellation September 21 Answer at 9. \nEKPC states that any further proceeding must define the exposure being secured, the \nquantity to which the rate applies, the date on which the obligation arises, objective \nreduction and release standards, the interaction with OA section 15.2.2, and the liquidity \nand default consequences created by the requirement. EKPC September 18 Answer at \n12."},{"page":82,"startToken":33925,"endToken":34342,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 82 - \nPJM proposed an initial credit rate of $1.5 million per committed RBP MW \nbecause it would collateralize approximately 50% of the estimated contractual value \nassociated with RBP commitments. However, as FirstEnergy notes, PJM does not \nsupport its 50% estimate with any quantitative measures, including an expected \nprobability of default, a loss-given-default assumption, a historical LSE default \nexperience, a liquidation or replacement period, or any other quantitative measure.333\nPJM also fails to demonstrate how the LSE Collateral requirements strike a reasonable \nbalance between protecting PJM’s markets and its members against the risk of default \nand ensuring that market participants have adequate flexibility to manage their collateral \nrequirements.334 PJM otherwise provides little flexibility for LSEs to manage their \ncollateral requirements, including a short timeline for posting collateral335 and limited, \nacceptable forms of collateral. Taken together, we find that PJM’s proposed LSE \nCollateral requirements may be unjust and unreasonable because they do not strike a \nreasonable balance between protecting PJM’s markets and its members against the risk of \ndefault and ensuring that market participants have adequate flexibility to manage their \ncollateral requirements. \n(e)\nPJM’s RBP Proposal May Be Just and \nReasonable if Modified \nWe find that additional record evidence is needed to determine if PJM’s proposed \nLSE Collateral requirement is just and reasonable. Therefore, as discussed elsewhere, we \nestablish paper hearing procedures and further briefing on appropriate collateral \nrequirements for RBP buyers. As part of their responses, parties should address (1) what \ninitial RBP Credit Rate is appropriate and (2) whether 45 days before the start of the \ndelivery year is sufficient time for LSEs to post collateral. \n333 FirstEnergy Protest at 9. \n334 See PJM Interconnection, L.L.C., 186 FERC ¶ 61,055 at P 29 (finding PJM’s \nproposed changes to its Peak Market Activity credit calculation strike a reasonable \nbalance between protecting PJM’s markets and its members against the risk of default \nand ensuring that market participants have adequate flexibility to manage their collateral \nrequirements). \n335 See SMECO Comments at 7 (“PJM proposes that the Electric Distributor’s \nRBO allocation be reported at no later than sixty days before the start of the [delivery \nyear]; PJM proposes to require the affected LSE to post the resulting collateral just fifteen \ndays later, at forty-five days before the [delivery year] begins. That leaves just a fifteen-\nday window to arrange collateral for an obligation whose amount it could not have \npredicted in advance, using a $1.5 million/MW RBP Credit Rate.”)."},{"page":83,"startToken":34342,"endToken":34625,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 83 - \niv.\nMiscellaneous \n(a)\nTiming Requirements \n(1)\nFiling \nPJM states that the RBP procurement window will open if and when a \nCommission order accepts PJM’s proposed RBP framework. PJM states that, to the \nextent the RBP framework is accepted by September 29, 2026, and absent significant \nrevisions or developments, PJM intends to open the procurement window on September \n30, 2026.336\n(2)\nPJM’s Proposal May Be Unjust and \nUnreasonable \nAs discussed above in Section IV.B, we accept PJM’s proposal for filing and \nsuspend it for five months to become effective February 28, 2027, subject to refund and \nto the outcome of paper hearing procedures. Because we are suspending the tariff \nrecords for five months, we find that PJM’s tariff records that propose actions during the \nsuspension window may be unjust and unreasonable. For example, the proposed Tariff \nprovides that the closing date of the bid solicitation for RBP is in October 2026.337\n(3)\nPJM’s RBP Proposal May Be Just and \nReasonable if Modified \nWe find that it may be just and reasonable to revise any deadlines set forth in the \ntariff records in accordance with the Commission’s action to suspend the tariff records \nfor five months. \n(b)\nRAA, Schedule 8.1D, Section 1.1 \n(1)\nFiling and Responsive Pleadings \nPJM’s proposed tariff revisions state that “[a]n FRR Entity may not use an \nExisting Generation Capacity Resource not owned by such FRR Entity as of June 1, 2027 \nor any resource committed through the Reliability Backstop Procurement to satisfy its \nCapacity FRR Plan.”338\n336 Transmittal at 3 n.5. \n337 Proposed Tariff, attach. DD, § 18.5(f). \n338 Proposed RAA, Schedule 8.1D, § 1.1."},{"page":84,"startToken":34625,"endToken":35012,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 84 - \nAEP and EKPC note that this provision appears to be a drafting error. They argue \nthis provision would unreasonably disallow FRR Entities from using both owned and \ncontracted resources.339\nIn response, PJM states that it inadvertently submitted this revision and did not \nintend to include this revision as part of the RBP proposal. PJM requests that the \nCommission reject this revised tariff record.340\n(2)\nDetermination \nIn accordance with PJM’s request to reject this inadvertently submitted tariff \nrecord, we reject PJM’s proposed tariff revisions to RAA, Schedule 8.1D, section 1.1. \n4.\nEL26-108-000 \nAs stated earlier, we are establishing a new FPA section 206 proceeding in Docket \nNo. EL26-108-000. In cases where, as here, the Commission institutes a section 206 \ninvestigation on its own motion, section 206(b) of the FPA requires that the Commission \nestablish a refund effective date that is no earlier than the date of publication by the \nCommission of notice of its intention to initiate such proceeding nor later than five \nmonths after the publication date. In such cases, in order to give maximum protection to \ncustomers, and consistent with our precedent, we have historically tended to establish the \nsection 206 refund effective date at the earliest date allowed by section 206, and we do so \nhere as well.341 That date is the date of publication of notice of initiation of the section \n206 proceeding in Docket No. EL26-108-000 in the Federal Register. \nSection 206(b) of the FPA also requires that, if no final decision is rendered by the \nconclusion of the180-day period commencing upon initiation of the section 206 \nproceeding, the Commission shall state the reason why it has failed to render such a \ndecision and state its best estimate as to when it reasonably expects to make such a \ndecision. As we are setting the section 206 proceeding in Docket No. EL26-108-000 for \nfurther proceedings, we expect that we would be able to render a decision within five \nmonths of the date of this order. \nThe Commission orders: \n339 AEP Protest at 34-35; EKPC Protest at 47. \n340 PJM Answer at 55 n.160. \n341 See, e.g., Idaho Power Co., 145 FERC ¶ 61,122 (2013); Canal Elec. Co., 46 \nFERC ¶ 61,153, order on reh’g, 47 FERC ¶ 61,275 (1989)."},{"page":85,"startToken":35012,"endToken":35283,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 85 - \n(A) PJM’s proposed Tariff and RAA revisions are hereby accepted for filing, \nsuspended for five months, effective February 28, 2027, subject to refund and the \noutcome of the further procedures ordered in this proceeding, as discussed in the body of \nthis order. \n(B) Paper hearing procedures are hereby established to address issues raised by \ncertain aspects of PJM’s proposal, as discussed in the body of this order. \n(C) Pursuant to the authority contained in and subject to the jurisdiction conferred \nupon the Federal Energy Regulatory Commission by section 402(a) of the Department of \nEnergy Organization Act and the FPA, particularly section 206 thereof, and pursuant to \nthe Commission’s Rules of Practice and Procedure and the regulations under the FPA (18 \nC.F.R. Chapter I), the Commission hereby institutes a proceeding in Docket No. EL26-\n108-000 concerning the justness and reasonableness of PJM’s tariff, as discussed in the \nbody of this order. \n(D) The Secretary shall promptly publish in the Federal Register a notice of the \nCommission’s initiation of the proceeding under section 206 of the FPA in Docket No. \nEL26-108-000. \n(E) The refund effective date in Docket No. EL26-108-000 established pursuant to \nsection 206 of the FPA shall be the date of publication in the Federal Register of the \nnotice discussed in Ordering Paragraph (D) above. \nBy the Commission. Chairman Swett is concurring with a separate statement attached. \n Commissioner Rosner is concurring with a separate statement \n attached. \n Commissioner See is concurring with a separate statement attached. \n Commissioner LaCerte is concurring with a separate statement \n attached. \n( S E A L ) \nDebbie-Anne A. Reese, \nSecretary."},{"page":86,"startToken":35283,"endToken":35504,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 86 - \nAppendix A – Tariff Records \nPJM Interconnection, L.L.C. \nIntra-PJM Tariffs \nx\nC-D, OATT Definitions – C-D (47.0.0)\nx\nE-F, OATT Definitions - E - F (45.0.0)\nx\nO-P-Q, OATT Definitions - O - P - Q (39.0.0)\nx\nR-S, OATT Definitions – R - S (47.0.0)\nx\nATTACHMENT DD.5.5, OATT ATTACHMENT DD.5.5 Eligibility for \nParticipation in RPM (7.0.0)\nx\nATTACHMENT DD.5.5A, OATT ATTACHMENT DD.5.5A Capacity Resource \nTypes (13.0.0)\nx\nOATT ATT DD.5.14, OATT ATTACHMENT DD.5.14 Clearing Prices and Charges \n(45.0.0)\nx\nOATT ATT DD.6.6, OATT ATTACHMENT DD.6.6 Offer Requirement for Capacity \nResour (4.0.0)\nx\nOATT ATT DD.6.6A, OATT ATTACHMENT DD.6.6A Offer Requirement for \nCapacity Perfo (6.0.0)\nx\nATTACHMENT DD.16, OATT ATTACHMENT DD.16. RELIABILITY \nBACKSTOP (3.0.0)\nx\nATTACHMENT DD.18, OATT ATTACHMENT DD.18 RELIABILITY \nBACKSTOP PROCUREMENT (0.0.0)\nx\nATTACHMENT DD.18.1, ATTACHMENT DD.18.1 Determination of Final RBP \nTarget (0.0.0)\nx\nATTACHMENT DD.18.2, ATTACHMENT DD.18.2 Qualifying New UCAP MW \n(0.0.0)\nx\nATTACHMENT DD.18.3, ATTACHMENT DD.18.3 Cost Allocation of RBP \nCharges, Credits (0.0.0)"},{"page":87,"startToken":35504,"endToken":35657,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 87 - \nx\nATTACHMENT DD.18.4, ATTACHMENT DD.18.4 Scope of the Reliability \nBackstop Procure (0.0.0)\nx\nATTACHMENT DD.18.5, ATTACHMENT DD.18.5 The Reliability Backstop \nProcurement Proc (0.0.0)\nx\nATTACHMENT DD.18.6, ATTACHMENT DD.18.6 RBP Resource Obligations \n(0.0.0)\nx\nATTACHMENT DD.18.7, ATTACHMENT DD.18.7 Exiting Transmission Owner \nRBP Obligation (0.0.0)\nx\nATTACHMENT DD.18.8, ATTACHMENT DD.18.8 Credit Requirements for RBP \nSellers (0.0.0)\nx\nATTACHMENT DD.18.9, ATTACHMENT DD.18.9 RBP Default Allocation (0.0.0)\nx\nRAA ARTICLE 1, RAA ARTICLE 1 -- DEFINITIONS (56.0.0)\nx\nRAA Article 7 Sec 2B, RAA Article 7 Sec 2B Responsibility to Pay RBP Charges \n(0.0.0)\nx\nRAA Article 7 Sec 2C, RAA Article 7 Sec 2C Provision of RBP Obligations (0.0.0)"},{"page":88,"startToken":35657,"endToken":35877,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 88 - \nAppendix B – Intervenors \n*Filed Comments \nAdvanced Energy United (AEU)* \nAmazon Energy LLC (Amazon)* \nAmeren Services Company \nAmerican Council on Renewable Energy \nAmerican Electric Power Service Corporation (AEP)* \nAmerican Municipal Power, Inc. (AMP)* \nAppalachian Voices \nAvangrid Networks, Inc. \nAvangrid Power, LLC (Avangrid, collectively with Avangrid Networks, Inc.) \nBase Power Inc. (Base Power)* \nBlue Ridge Power Agency (Blue Ridge)* \nBoston Energy Trading and Marketing LLC \nBrookfield Renewable Trading and Marketing LP \nBuckeye Power, Inc. \nCalibrant Energy (Calibrant)* \nCitizens’ Electric Company of Lewisburg, PA \nConsolidated Edison Company of New York, Inc. (ConEd)342\nConstellation Energy Generation, LLC (Constellation)* \nCPV Power Holdings, LP (CPV)* \nCyrusOne LP \nData Center Coalition (DCC)* \nDelaware Division of the Public Advocate*343\nDominion Energy Services, Inc. (Dominion)* \nDuke Energy Corporation \nDuquesne Light Company (Duquesne) (Indicated PJM Transmission Owners (Indicated \nPJM TOs), collectively with FirstEnergy Transmission Companies)* \nE-Cubed Policy Associates, LLC (E-Cubed)* \nEast Kentucky Power Cooperative, Inc. (EKPC)* \nEDF Power Solutions, Inc. \nEdison Electric Institute \nElectric Power Supply Association \n342 ConEd filed two motions to intervene, one out-of-time. \n343 Delaware Division of the Public Advocate, District of Columbia Office of \nPeople’s Counsel, Illinois Citizens Utility Board, Office of the Illinois Attorney General, \nMaryland Office of the People’s Counsel, and New Jersey Division of Rate Counsel \n(collectively, Joint Consumer Advocates (JCA)) submitted a joint protest."},{"page":89,"startToken":35877,"endToken":36124,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 89 - \nEnel X North America, Inc. \nEnergy LLC \nEnergy Trading Institute \nENGIE North America Inc. \nEquinix Inc. (Equinix)* \nExelon Corporation \nFirstEnergy Service Company344 (FirstEnergy)* \nGoogle LLC* \nIllinois Citizens Utility Board \nIllinois Commerce Commission (ICC)* \nIllinois Municipal Electric Agency \nInstitute for Policy Integrity at New York University School of Law (Policy Integrity)345* \nInvenergy Solar Development North America LLC \nInvenergy Thermal Development LLC \nInvenergy Wind Development North America LLC \nJ-POWER USA Development Co., Ltd. \nKentucky Attorney General \nLS Power Development, LLC \nMaryland Office of People’s Counsel \nMaryland Public Service Commission \nMichigan Public Service Commission \nMN8 Energy LLC \nMonitoring Analytics, LLC, acting in its capacity as Independent Market Monitor for \nPJM (Market Monitor)* \nNational Grid plc346\nNew Jersey Board of Public Utilities \nNew Jersey Division of Rate Counsel \nNicholas Max Neal and David Neal, Delaware Standard Offer Service Ratepayers \n344 FirstEnergy Service Company submitted a motion to intervene as agent for its \nfranchised public utility and transmission-owning public utility affiliates Ohio Edison \nCompany; The Cleveland Electric Illuminating Company; The Toledo Edison Company; \nFirstEnergy Pennsylvania Electric Company; and the FirstEnergy Transmission Owners \n(collectively, Jersey Central Power & Light Company; Monongahela Power Company; \nThe Potomac Edison Company; American Transmission Systems, Incorporated; \nKeystone Appalachian Transmission Company; Mid-Atlantic Interstate Transmission, \nLLC; and Trans-Allegheny Interstate Line Company). \n345 Policy Integrity filed comments but did not file a motion to intervene. \n346 National Grid plc submitted a motion to intervene on behalf of its competitive \nenergy development corporation National Grid Ventures."},{"page":90,"startToken":36124,"endToken":36386,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 90 - \n(Movants)* \nNorth Carolina Electric Membership Corporation (NCEMC)* \nNortheastern Rural Electric Membership Corporation \nNorthern Virginia Electric Cooperative, Inc. (NOVEC)* \nNRG Business Marketing LLC347* \nOffice of the Illinois Attorney General \nOffice of the Ohio Consumers’ Counsel (OCC)* \nOffice of the People’s Counsel for the District of Columbia \nOhio Energy Leadership Council (OELC)* \nOld Dominion Electric Cooperative (ODEC)* \nOrganization of PJM States, Inc. (OPSI)* \nPennsylvania Office of Consumer Advocate (PA OCA)* \nPennsylvania Public Utility Commission \nPersistence Analytics Group LLC* \nPJM Industrial Customer Coalition (PJMICC)* \nPJM Power Providers Group (P3)* \nPPL Electric Utilities Corporation* \nPublic Citizen, Inc \nPublic Service Commission of West Virginia (PSCWV)* \nPublic Utilities Commission of Ohio’s Office of the Federal Energy Advocate (Ohio \nFEA)* \nRetail Energy Supply Association (RESA)* \nShell Energy North America (US), L.P. \nSierra Club348* \nSolar Energy Industries Association (SEIA)* \nSouthern Maryland Electric Cooperative, Inc. (SMECO)* \nTalen Energy Corporation (Talen)* \nThe Williams Companies, Inc. \nTract Holding Company I, LLC (Tract)* \nVerrus LLC \n347 NRG Business Marketing LLC submitted a motion to intervene on behalf of its \npublic utility affiliates Aspen Gen Funding, LLC; Direct Energy Business, LLC; \nDoswell, LLC; Energy Plus Holdings LLC; Enerwise Global Technologies, LLC dba \nCPower; Green Mountain Energy Company; Helix Ironwood, LLC; Independence \nEnergy Group LLC; LSP University Park, LLC; Midwest Generation LLC; NRG \nCurtailment Solutions, Inc.; Reliant Energy Northeast LLC; Riverside Generating \nCompany, LLC; Stream Energy Pennsylvania, LLC; University Park Energy, LLC; and \nXOOM Energy, LLC (NRG Companies, collectively). \n348 Sierra Club filed comments jointly with the National Resource Defense \nCouncil, who did not file a motion to intervene."},{"page":91,"startToken":36386,"endToken":36420,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n- 91 - \nVirginia Municipal Electric Association No. 1 \nVirginia State Corporation Commission \nVistra Corp. (Vistra)* \nVoltus, Inc. \nWellsboro Electric Company (Citizens’ Electric, collectively with Citizens’ Electric \nCompany of Lewisburg, PA)"},{"page":92,"startToken":36420,"endToken":36629,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \nPJM Interconnection, L.L.C. \nDocket No. ER26-3380-000\nEL26-108-000\n(Issued September 29, 2026) \nSWETT, Chairman, concurring: \nAmerican ratepayers and utilities need urgency, clarity, and discipline—none of \nwhich PJM appears capable of delivering at this time. The Reliability Backstop \nProcurement proposal came before us on the last possible statutory day to open a \nprocurement window on September 30. Whether by accident or incompetence, that \ntiming left the Commission no meaningful opportunity to issue a deficiency letter, seek \nadditional record development, or establish hearing procedures to attempt to rehabilitate \nthe mess we received. \nThis Commission will not be forced into accepting a deeply flawed, eleventh-hour \nprocurement mechanism with billion-dollar implications for consumers. Today we triage \nthe issues and urge PJM to promptly remedy them in a Federal Power Act Section 205 \nfiling. We accept certain parts of the proposal that advance urgently needed capacity \nprocurement, find that other components require reform, and provide guidance to inform \nexpeditious resubmission. \nWe are prepared to promptly act on a subsequent proposal that addresses the \nconcerns raised in this order and meets the standards of the Federal Power Act. The \nregion’s reliability hangs in the balance. \nFor these reasons, I respectfully concur. \n________________________ \nLaura V. Swett \nChairman"},{"page":93,"startToken":36629,"endToken":36946,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \nPJM Interconnection, L.L.C.\nDocket No. ER26-3380-000\n(Issued September 29, 2026) \nROSNER, Commissioner, concurring: \nI concur in today’s order because, at its core, our responsibility to the 67 million \npeople in PJM is to keep the lights on. While the record reflects a wide range of views on \nhow best to address the emerging reliability challenges, the downside risk of inaction far \noutweighs the risk of an imperfect solution. It is not a close call. \nThe limited set of guidance we give PJM to revise its proposal will enable PJM to \nassign costs to those responsible (i.e. to the zones with data center growth) for the \nresource adequacy shortfall, consistent with cost causation principles, and it is my hope \nthat PJM will act on this guidance swiftly so that needed generation may be procured. \nMany of the issues driving this filing extend beyond PJM’s jurisdiction to solve \nalone. States and retail authorities must play an active role – particularly in establishing \nlarge-load retail tariffs, enforcing collateral requirements, and establishing clear rules for \nwhich customers should be curtailed first when circumstances require it (Hint: homes, \nhospitals, and schools should never be curtailed before data centers). As the order \nacknowledges,1 these are decisions that sit squarely with states and their regulators, and \nmeaningful progress requires their continued leadership. \nIn the longer term PJM and its stakeholders must return to market fundamentals. \nLoad and supply should have strong incentives to hedge, manage their risks, and procure \nthe capacity they rely upon. Market discipline – not ad hoc backstops – must again \nbecome the primary safeguard for reliability. \nFor these reasons, while acknowledging the imperfections in the filing, I agree that \ntaking action today is warranted, and I respectfully concur. \nFor these reasons, I respectfully concur. \n________________________ \nDavid Rosner \nCommissioner \n1 PJM Interconnection, L.L.C., 196 FERC ¶ 61,245, at P 161 (2026)."},{"page":94,"startToken":36946,"endToken":37337,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \nPJM Interconnection, L.L.C.\nDocket Nos. ER26-3380-000\n(Issued September 29, 2026) \nSEE, Commissioner, concurring: \nPJM needs more generation: Soaring electricity demand from data centers, \nartificial intelligence, domestic manufacturing, and other strategic industries continues to \nchallenge a region that faces increasingly tight supply. Meeting that demand requires \nsufficient generation, including dependable resources that support the system around the \nclock. PJM must move fast to secure the resources to serve its growing system. \nBut how PJM—really, PJM’s ratepayers—pays for those resources matters. As I \nhave said before, customers that drive new costs should bear appropriate responsibility \nfor them. Existing customers should not be left paying costs attributable to new demand. \nThat principle is particularly important here where PJM proposes a backstop procurement \nspecifically to deal with the capacity shortfall that rapid load growth largely drove. \nPJM needs urgent action and this mechanism, the RBP, can be a critical tool to \nbring additional capacity to the region. Unfortunately, though, PJM missed the mark on \nan important element of its proposal: it did not adequately ensure that the procurement’s \ncosts will be allocated to the customers who drive its need. \nToday’s order is not perfect; the filing it responds to, even less. But today the \nCommission provides PJM a path forward to solve what its current proposal lacks when it \ncomes to fair cost allocation. PJM should move quickly to take it. \nThat work must include a serious focus on load forecasting. After years of \nrelatively flat electricity demand, regulators and grid operators need to adjust to sustained \nand asymmetric growth. That means better load forecasts, a clearer picture of which \nprojects will materialize, and enough generation and infrastructure to serve them. Better \ninformation about where, when, and why load is growing also provides a stronger \nfoundation for determining who should bear the costs associated with serving that \ngrowth. \nPJM does not have the luxury of standing still. The region needs additional \ngeneration, and I encourage PJM to swiftly return to the Commission with a section 205 \nfiling we can accept so that the procurement can move forward quickly. In doing so, \nPJM must better ensure that the customers driving new costs bear appropriate \nresponsibility for them and that existing customers are not left paying the bill instead. \nFor these reasons, I respectfully concur."},{"page":95,"startToken":37337,"endToken":37347,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n - 2 - \n____________________ \nLindsay S. See \nCommissioner"},{"page":96,"startToken":37347,"endToken":37674,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \nPJM Interconnection, L.L.C. \nDocket Nos. \nER26-3380-000\nEL26-108-000\n(Issued September 29, 2026) \nLACERTE, Commissioner, concurring: \nI concur in today’s order but write separately as a reminder of what this order \nis—or should be—about. Reliability Backstop Procurement is designed to make sure the \ncosts of the large load at issue here are appropriately allocated to that load and not to \nother consumers and, in that vein, it is also an attempt to get new assets onto the PJM grid \nin a time of desperate need. \nThis is not a problem with an exceedingly easy or even single solution. While a \nperfect solution may not exist, it does not mean this is an unsolvable problem. \nThis moment must be met. We must do so not only because it is one of the many \nvital issues we are presented with in PJM and other regions of this country, but because it \nis important for Americans to do so. \nThe vital nature of the large load integration issue to all Americans is highlighted \nby the very existence of the January 2026 Statement of Principles Regarding PJM1 in \nwhich the White House National Energy Dominance Council and the governors of all 13 \nPJM states joined together to address these large load issues as well as the March 2026, \nWhite House Ratepayer Protection Pledge which addressed that new large loads will, at a \nminimum, “build, bring, or buy the new generation resources and electricity needed to \nsatisfy their new energy demands, paying the full cost of those resources”2 and which \nreceived broad consensus from utilities, cooperatives, data center developers, and \ngovernors.3\n1 U.S. Department of Energy, Statement of Principles Regarding PJM (Jan. 2026), \nhttps://www.energy.gov/documents/statement-principles-regarding-pjm. \n2 The White House, Ratepayer Protection Pledge (Mar. 4, 2026), \nhttps://www.whitehouse.gov/wp-content/uploads/2026/07/Ratepayer-Protection-Pledge-\nSigned.pdf.\n3 The White House, Ratepayer Protection Pledge (Mar. 2026),"},{"page":97,"startToken":37674,"endToken":37818,"text":"Docket Nos. ER26-3380-000 and EL26-108-000 \n - 2 - \nWhat all of this tells me is that time is of the essence. While we could orbit these \nissues in additional briefings that would cause additional delay to the reliability backstop \nauction and the hope for relief it provides. \nPJM: you must take action. You alone have the ability to resolve the outstanding \nissues in the most time efficient manner by making a section 205 filing under the \ntimelines set forth in this order—or sooner—that thoughtfully addresses the infirmities of \nthe original filing addressed in this order. Do not deviate from the principles of ratepayer \nprotection in that filing. \nA competent and effective RTO can take this half-baked cake and finish the job. \nDoes PJM meet that description? They’re on the clock. \nFor these reasons, I respectfully concur. \n______________________________ \nDavid LaCerte \nCommissioner \nhttps://www.whitehouse.gov/ratepayer-protection-pledge."}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":668,"startToken":0,"endToken":394},{"p":2,"at":668,"title":"I. Background","method":"printed heading","endPage":2,"endAt":671,"startToken":394,"endToken":395},{"p":2,"at":671,"title":"Background","method":"printed heading","endPage":7,"endAt":51,"startToken":395,"endToken":2159},{"p":7,"at":51,"title":"II. Filing","method":"printed heading","endPage":8,"endAt":1762,"startToken":2159,"endToken":2885},{"p":8,"at":1762,"title":"III. Notice of Filing and Responsive Pleadings","method":"printed heading","endPage":9,"endAt":256,"startToken":2885,"endToken":3057},{"p":9,"at":256,"title":"IV. Discussion","method":"printed heading","endPage":9,"endAt":260,"startToken":3057,"endToken":3058},{"p":9,"at":260,"title":"Discussion","method":"printed heading","endPage":9,"endAt":272,"startToken":3058,"endToken":3059},{"p":9,"at":272,"title":"A. Procedural Matters","method":"printed heading","endPage":9,"endAt":1024,"startToken":3059,"endToken":3178},{"p":9,"at":1024,"title":"B. Substantive Matters","method":"printed heading","endPage":97,"endAt":1005,"startToken":3178,"endToken":37818}]}