{"document":{"slug":"filing-20260910-5296","title":"Motion for Leave to Answer and Answer of PJM Interconnection, L.L.C. to Comments and Protests re the 07/31/2026 revised Open Access Transmission Tariff filing et al","issued":"2026-09-10","accession":"20260910-5296","docket":"ER26-3380-000","group":"PJM filings","filer":"PJM Interconnection, L.L.C.","kind":"comments","file":"sources/originals/20260910-5296_01.pdf","url":"https://www.pjm.com/-/media/DotCom/documents/ferc/filings/2026/20260910-er26-3380-000.pdf","sha256":"d4178f9996d3c6252e5f39ef4be7a1d1aed47bc33ab160725e316443cc95677c","pages":112,"tokens":36584,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":443,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \n \n) \nPJM Interconnection, L.L.C.                      ) \nDocket No. ER26-3380-000 \n) \n \nMOTION FOR LEAVE TO ANSWER AND ANSWER OF  \nPJM INTERCONNECTION, L.L.C. \nPJM Interconnection, L.L.C. (“PJM”), pursuant to Federal Energy Regulatory \nCommission (“Commission” or “FERC”) Rules of Practice and Procedure 212 and 213,1 \nsubmits this Motion for Leave to Answer2 and Answer (“Answer”) to comments and \nprotests filed in response to PJM’s proposal, filed July 31, 2026 (“July 31 Filing”),3 \nrevising its Open Access Transmission Tariff (“Tariff”) and the Reliability Assurance \nAgreement Among Load Serving Entities in the PJM Region (“RAA”)4 to establish the \nReliability Backstop Procurement (“RBP”) in order to address resource adequacy concerns \nstemming from large loads (“RBP proposal”).  The RBP proposal is one part of a multi-\n \n1 18 C.F.R. §§ 385.212, 385.213. \n2 Although Commission Rule 213(a)(2) does not generally permit answers to protests, the Commission \npermits answers for good cause shown, such as when an answer contributes to a more accurate and complete \nrecord or provides useful information that assists the Commission’s deliberative process.  This answer will \naid the Commission’s decision-making process by providing responses to the various comments and protests \nfiled in response to PJM’s filings in this docket.  PJM therefore asks that the Commission accept this Answer.  \nSee, e.g., PJM Interconnection, L.L.C., 182 FERC ¶ 61,073, at P 13 (2023) (“We accept the answers of \nJ-Power [USA Development Co., Ltd.], [PJM Power Providers Group], PJM, Public Interest Entities, and the \n[Independent] Market Monitor [for PJM] because they have provided information that assisted us in our \ndecision-making process.”); N.Y. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 158 FERC \n¶ 61,137, at P 29 (2017) (“We will accept the Companies’ and the Complainants’ answers because they have \nprovided information that assisted us in our decision-making process.”), order granting in part & denying in \npart reh’g & clarification, 170 FERC ¶ 61,120, order on clarification, 171 FERC ¶ 61,114 (2020); Colonial \nPipeline Co., 157 FERC ¶ 61,173, at P 23 (2016) (“In the instant case, the Commission will accept the \nProtestors’ Answers and Colonial [Pipeline Co.]’s Answer because they have provided information that \nassisted us in our decision-making process.”).   \n3 PJM Interconnection, L.L.C., Reliability Backstop Procurement to Address Resource Adequacy Concerns \nStemming from Large Loads of PJM Interconnection, L.L.C., Docket No. ER26-3380-000 (July 31, 2026). \n4 Capitalized terms not otherwise defined herein have the meaning as defined in the July 31 Filing, Tariff, \nRAA, Amended and Restated Operating Agreement of PJM (“Operating Agreement”), and Consolidated \nTransmission Owners Agreement (“CTOA”)."},{"page":2,"startToken":443,"endToken":806,"text":"2 \npronged, ongoing effort by PJM to respond to the challenges stemming from the influx of \nlarge loads into the PJM Region,5 and also just one part of a multi-pronged implementation \nof the Statement of Principles Regarding PJM issued on January 16, 2026, by the National \nEnergy Dominance Council (“NEDC”) and the 13 governors of the PJM states.6   \nAs discussed below, none of the protests, limited protests, comments, requests for \nclarification, or answers submitted in this matter7 undermine the fact that PJM’s RBP \nproposal is a just and reasonable and not unduly discriminatory or preferential means to \nprocure capacity through a one-time backstop procurement.  This proposal addresses the \ninflux of large loads while maintaining resource adequacy, reliability, and affordability in \na manner that respects the divide between state and federal authorities and avoids \ndisrupting existing commercial arrangements.8  Indeed, numerous PJM stakeholders and \nstate commissions, representing a diverse range of interests, expressed general support for \nthe RBP proposal.9  For the reasons set forth below and in PJM’s July 31 Filing, the RBP \n \n5 David E. Mills, PJM Board of Managers Chair, Board Decisional Letter on Critical Issue Fast Path - Large \nLoad Additions, PJM Board of Managers (Jan. 16, 2026), https://www.pjm.com/-/media/DotCom/about-\npjm/who-we-are/public-disclosures/2026/20260116-pjm-board-letter-re-results-of-the-cifp-process-large-\nload-additions.pdf [https://perma.cc/P57T-ZXYJ]. \n6 Statement of Principles Regarding PJM, National Energy Dominance Council, 1 (Jan. 16, 2026), \nhttps://www.energy.gov/documents/statement-principles-regarding-pjm \n[https://perma.cc/35HJ-W56E] \n(“NEDC/PJM Governors’ Principles”).  The PJM state governor signatories are the governors of the 13 states \nof Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, \nPennsylvania, Tennessee, Virginia, and West Virginia. \n7 See Appendix A, Protests, Limited Protests, Comments, and Requests for Clarification attached hereto.  \n8 While PJM’s Answer does not address every argument raised by intervenors, silence on any argument \nshould not be deemed as acceptance of the arguments raised.   \n9 See, e.g., NJ BPU Comments at 7; Ohio FEA Comments at 6; OPSI Comments at 4; NRG Limited Protest \nat 2; DCC Comments at 2-3; Equinix Comments at 4; Base Power Comments at 1; PPL Limited Protest and \nRequest for Clarification at 1."},{"page":3,"startToken":806,"endToken":1158,"text":"3 \nproposal should be accepted, and made effective, no later than September 29, 2026, as \nrequested.10 \nI. \nANSWER \nA. \nThe RBP Proposal Is a Measured and Timely Response that Received \nSupport from a Diverse Set of Stakeholders and Reflects the Fruits of \nPJM’s Ongoing Efforts to Engage with Stakeholders.  \nThe RBP proposal was constructed with an eye toward how to best serve the needs \nof the PJM Region, while also supporting PJM’s core mission of maintaining the reliability \nof the electric power grid to keep the lights on for 67 million people across 13 states and \nthe District of Columbia.  The RBP proposal addresses the “Herculean challenge”11 \npresented by the recent resource adequacy shortfalls in the PJM Region, while \nsimultaneously:  \n• maintaining resource adequacy, reliability, and affordability;  \n• respecting the divide between state and federal authorities through a \ncarefully constructed cooperative federalism framework;  \n• avoiding disruption to existing commercial arrangements;  \n• supporting a concurrent bilateral contracting pathway; and \n• remaining consistent with the NEDC/PJM Governors’ Principles.   \nDespite the complexity of the challenges and the numerous considerations that PJM was \nrequired to account for and balance, the RBP proposal garnered broad support from a \ndiverse set of intervenors.12  In addition, even after the July 31 Filing, PJM continued to \n \n10 The RBP procurement window will open if and when a Commission order accepts PJM’s proposed RBP \nframework.  To the extent the RBP framework is accepted by September 29, 2026, and absent significant \nrevisions or developments, PJM intends to open the procurement window on September 30, 2026.   \n11 NOVEC Protest at 4 (The Herculean challenge is “[t]he success, then, of the RBP relies on the coordination \nof a multidimensional amalgam of state regulatory commissions, legislatures, governors, local governments, \nand utilities across thirteen states and the District of Columbia.”). \n12 See, e.g., Equinix Comments at 1-2, 18; OPSI Comments at 1-3; Ohio FEA Comments at 1-3, 6; Vistra \nProtest at 1-2; ICC Comments at 1-3; NRG Limited Protest at 1-3; SMECO Comments at 1-2; AEU \nComments at 1-2; CPV Comments at 1-2; NJ BPU Comments at 1-3; PIOs Limited Protest at 1-3, 9; PPL"},{"page":4,"startToken":1158,"endToken":1413,"text":"4 \nactively engage with intervenors, and this Answer reflects several proposed clarifications \nand/or adjustments to the RBP proposal, which represent the fruits of PJM’s ongoing \nstakeholder engagement.  Furthermore, PJM has been providing states with additional \nguidance on how PJM and states will coordinate to implement the RBP proposal, while \nstates have worked towards developing, or further developing, applicable rules to account \nfor cost allocation of RBP Resources to retail load.  Together, PJM and the states are \ncontinuing to work in tandem towards the shared goal of ensuring the orderly, transparent, \nand timely execution of the proposed RBP. \n1. \nThe RBP proposal received significant support from a diverse set of \nintervenors. \nThe RBP proposal received comments of general support for the RBP proposal \nfrom a diverse set of stakeholders13 including, but not limited to:   \n \nLimited Protest and Request for Clarification at 1; Google Comments at 1, 8; DCC Comments at 2-3; Amazon \nComments at 2; AEP Limited Protest at 2; Dominion Partial Protest and Comments at 2. \n13 See, e.g., Equinix Comments at 1-2, 18; OPSI Comments at 1-3; Ohio FEA Comments at 1-3, 6; Vistra \nProtest at 1-2; ICC Comments at 1-3; NRG Limited Protest at 1-3; SMECO Comments at 1-2; AEU \nComments at 1-2; CPV Comments at 1-2; NJ BPU Comments at 1-3; PIOs Limited Protest at 1-3, 9; PPL \nLimited  Protest and Request for Clarification at 1; Google Comments at 1; DCC Comments at 2-3; Amazon \nComments at 2; AEP Limited Protest at 2; Dominion Partial Protest and Comments at 2."},{"page":5,"startToken":1413,"endToken":1959,"text":"5 \n• State public utility and advocacy groups:  the Organization of PJM States, \nInc. (“OPSI”),14 the Ohio’s Office of the Federal Energy Advocate (“Ohio \nFEA”),15 and the NJ BPU;16 \n• Transmission Owners:  PPL Electric Utilities Corporation (“PPL”)17 and \nDominion Energy Services, Inc. (“Dominion”);18 \n• Suppliers of capacity, developers, and trade groups representing them:  \nAdvanced Energy United (“Advanced Energy United” or “AEU”),19 Solar \n \n14 OPSI Comments at 1 (The following OPSI members support OPSI’s comments in support of PJM’s July 31 \nFiling:  the Delaware Public Service Commission, Public Service Commission of the District of Columbia, \nIllinois Commerce Commission (“ICC”), Indiana Utility Regulatory Commission, Kentucky Public Service \nCommission, Maryland Public Service Commission, Michigan Public Service Commission, New Jersey \nBoard of Public Utilities (“NJ BPU”), North Carolina Utilities Commission, Public Utilities Commission of \nOhio, Pennsylvania Public Utility Commission, Tennessee Public Utility Commission, and Virginia State \nCorporation Commission); see also id. (“OPSI supports the filing because the proposed revisions strengthen \nregional resource adequacy while appropriately recognizing that implementation will require complementary \nstate action to ensure that RBP costs are allocated to the appropriate retail loads.”). \n15 Ohio FEA Comments at 3 (“The Ohio FEA supports the filing.”); id. at 6 (“PJM’s RBP is a timely effort \nto address reliability concerns caused by significant data center load growth in the region.  We urge the \nCommission to approve the filing to secure long-term capacity commitments from new resources to meet \nescalating demand and to mitigate any compounding effect on PJM’s energy and capacity markets or other \nratepayers.”). \n16 NJ BPU Comments at 1 (“[T]he Board overall supports PJM’s proposal. . . . [T]he Board supports the \nTariff revisions to add the targeted one-time procurement RBP starting in 2026 . . . .”); id. at 3 (“The Board \nsupports PJM’s proposed Tariff revisions to conduct this backstop before waiting for an additional BRA to \nclear short.  The Board also supports assigning the costs of this procurement to zones in proportion to their \nexpected large load additions.  This is necessary to ensure large loads can be made responsible for the costs, \nwhile recognizing that states have ultimate authority over retail cost allocations.”); id. at 7 (“[T]the Board \nultimately supports PJM’s RBP proposal and the Board recommends approving it so PJM can run the central \nprocurement in 2026.”). \n17 PPL Limited Protest and Request for Clarification at 1 (PPL “is generally supportive of the [RBP] Filing.”). \n18 Dominion Partial Protest and Comments at 3 (“Dominion generally supports the RBP as a one-time \nprocurement to bring the PJM region to a more stable state of resource adequacy and pave the way for holistic \nmarket design reforms that will support the infrastructure needed to reliably serve load growth in the \nregion. . . .  The PJM region must address near-term deficiencies to begin focusing on the long-term solution, \nwhich is why Dominion Energy supports the RBP.”). \n19 AEU Comments at 1 (“[Advanced Energy] United generally supports PJM’s July 31, 2026, filing as the \nbest available solution to address the pressing challenge of rapid load growth and slow resource entry in a \nmanner that avoids putting even greater cost burden on existing customers not contributing to the resource \nadequacy shortfall.”); id. at 28 (“[Advanced Energy] United accepts PJM’s proposed [RBP] as a necessary \ntool to address the extraordinary challenges facing the region.”)."},{"page":6,"startToken":1959,"endToken":2494,"text":"6 \nEnergy Industries Association (“SEIA”),20 CPV Power Holdings, LP \n(“CPV”),21 and Base Power, Inc. (“Base Power”);22 \n• Load Serving Entities (“LSE”):  NRG Companies (“NRG”);23  \n• Public Interest Organizations (“PIO”): Sierra Club and Natural \nResources Defense Council;24 and \n• Large Loads: Data Center Coalition (“DCC”),25 Google LLC \n(“Google”),26 and Equinix Inc. (“Equinix”).27 \nFurthermore, a subset of the supporting intervenors—ranging from state public \nutility commissions to end-use customers—expressly urge the Commission to accept the \n \n20 SEIA Comments at 1 (“SEIA does not oppose the RBP Proposal.”); id. at 13 (“SEIA supports PJM’s effort \nto address the resource adequacy shortfall on an expedited basis and appreciates the opportunity to provide \nthese comments.”). \n21 CPV Comments at 1 (“CPV supports the RBP Proposal and believes it is a critical step toward restoring \nresource adequacy in the PJM region.”). \n22 Base Power Comments at 1 (“Base [Power] supports the RBP and the overall structure of the proposed \nauction.”); id. at 3 (“Base [Power] supports PJM’s RBP proposal and appreciates PJM’s positive engagement \nwith stakeholders on the peak-shaving opt-out structure.”). \n23 NRG includes the following subsidiaries of NRG Energy, Inc.:  NRG Business Marketing LLC; Aspen \nGen Funding, LLC; Direct Energy Business, LLC; Doswell Limited Partnership; Energy Plus Holdings LLC; \nEnerwise Global Technologies, LLC d/b/a CPower; Green Mountain Energy Company; Helix Ironwood, \nLLC; Independence Energy Group LLC; LSP University Park, LLC; Midwest Generation LLC; NRG \nCurtailment Solutions, Inc.; Reliant Energy Northeast LLC; Riverside Generating Company, LLC; Stream \nEnergy Pennsylvania, LLC; University Park Energy, LLC; and XOOM Energy, LLC.  NRG Limited Protest \nat 1 n.3; see also id. at 1 (“The NRG Companies are supportive of the RBP concept . . . .”); id. at 3 (“[T]he \nNRG Companies generally support PJM’s RBP proposal as a necessary ‘stop-gap solution[]’ to fill the \nreliability gap.” (second alteration in original) (footnote omitted)).       \n24 PIOs Limited Protest at 10 (“PIOs generally support PJM’s Reliability Backstop Procurement \nproposal . . . . .”); id. at 1 (“PIOs urge the Commission to approve PJM’s RBP Filing with a \nmodification . . . .”). \n25 DCC Comments at 2 (“Given the urgency of PJM’s resource adequacy challenge, DCC supports moving \nforward with the RBP as a limited, one-time backstop.”); id. at 8 (“DCC supports the Commission’s \nacceptance of PJM’s proposed [RBP] as a limited, one-time measure to address the immediate resource \nadequacy shortfall.”). \n26  Google Comments at 1 (“Google commends PJM for taking steps to ensure reliability, which must remain \nits first priority.”); id. at 8 (“Google recognizes that RBP may be a reasonable response to the current resource \nadequacy shortfall . . . .”). \n27 Equinix Comments at 1-2 (“Equinix supports the adoption of the RBP on the timeline proposed by PJM.  \nIt is an urgent and necessary mechanism which, if applied as intended as a one-time backstop, can help \nsupport much-needed near-term stability for both market and reliability conditions.”); id. at 4 (“Equinix \nsupports PJM’s RBP approach as a one-time response to a severe resource adequacy shortfall posing a near-\nterm threat to reliability.  Equinix urges the Commission to accept the RBP on PJM’s proposed \ntimeline . . . .”); id. at 18 (“Equinix supports the [RBP] as a one-time mechanism and urges the Commission \nto accept it so that the procurement window may open as scheduled.”)."},{"page":7,"startToken":2494,"endToken":2908,"text":"7 \nRBP proposal, particularly as the challenges posed by large-load growth require decisive \naction.28   \nThe RBP proposal is, at bottom, a balanced and a middle ground approach.  This \nfact is borne out again and again by the totality of the protests and comments filed in the \nabove-captioned docket, which reflect that, on nearly every major issue, intervenors have \nfiled critiques from different sides of that issue.  Perhaps the most readily apparent example \nis the intervenor responses to the proposed $555/megawatt (“MW”)-day Unforced \nCapacity (“UCAP”) cap on the maximum willingness to pay—some intervenors assert that \nthe cap is too low, while others claim that it is too high.  As CPV appropriately and \naccurately states in its filed comments: \nThe RBP is a necessary and timely response to [PJM’s] growing \nresource adequacy challenge . . . . The RBP Proposal combines \nfeedback from the diverse group of parties that participated in the \n[Critical Issue Fast Path (“CIFP”)] to yield an overall package that \naims to protect ratepayer interests while still providing the decisive \naction that the moment calls for.29   \n \n28 NJ BPU Comments at 7 (“[T]he Board ultimately supports PJM’s RBP proposal and the Board \nrecommends approving it so PJM can run the central procurement in 2026.”); Ohio FEA Comments at 6 (The \nOhio FEA urges “the Commission to approve the filing to secure long-term capacity commitments from new \nresources to meet escalating demand and to mitigate any compounding effect on PJM’s energy and capacity \nmarkets or other ratepayers.”); OPSI Comments at 4 (“OPSI respectfully encourages the Commission to \naccept PJM’s proposed Tariff and RAA revisions and permit PJM to implement the RBP while continuing \nto pursue related reforms necessary to address the challenges posed by large-load growth.”); DCC Comments \nat 2-3 (DCC “urges the Commission to accept PJM’s filing.”); Equinix Comments at 4 (“Equinix urges the \nCommission to accept the RBP on PJM’s proposed timeline while making limited, discrete modifications \nand clarifications . . . .”); see also PIOs Limited Protest at 1 (“PIOs urge the Commission to approve PJM’s \nRBP Filing with a modification . . . .”); NRG Limited Protest at 2 (“[T]he NRG Companies respectfully urge \nthe Commission to accept the July 31 Filing subject to the modifications proposed . . . .”). \n29 CPV Comments at 1-2; id. at 3 (“CPV respectfully urges [with one limited clarification,] the Commission \nto act by, and accept the RBP Proposal and Tariff changes subject to a compliance filing effective, \nSeptember 29, 2026, as PJM requested.” (citing to July 31 Filing, Transmittal at 2-4))."},{"page":8,"startToken":2908,"endToken":3316,"text":"8 \n2. \nPJM has continued to engage with the stakeholder community and \nis amenable to several clarifications and adjustments to the RBP \nproposal that have been proposed by intervenors.  \nPJM appreciates the active engagement of its stakeholders on the RBP proposal and \nthe constructive feedback from the stakeholder community.  PJM agrees with Base Power, \nas well as other intervenors, that the RBP proposal has been shaped and informed by PJM’s \n“positive and constructive engagement with stakeholders” during and following the CIFP, \nin spite of the “compressed timeline.”30   \nIn fact, since the July 31 Filing, PJM has continued to engage with its stakeholders \nand answer questions about the implementation of the RBP proposal.  After conducting \nthree post-CIFP workshops to discuss and answer questions concerning RBP \nimplementation details,31 and carefully considering comments, protests, requests for \nclarification, and answers filed in the above-captioned docket, PJM responds, in this \nAnswer, to feedback from intervenors, and provides certain requested clarifications to the \nRBP proposal.  In several instances, as PJM discusses, below, PJM is amenable to discrete \n \n30 Base Power Comments at 1; see also PPL Limited Protest and Request for Clarification at 1 (“PPL Electric \ngreatly appreciates the engagement of the [PJM] stakeholder community and the work of the PJM Board and \nstaff in acting to address the capacity deficiencies arising from the 2027/2028 and 2028/2029 Reliability \nPricing Model (“RPM”) Auctions[.]”); Calibrant Request for Clarification at 2 (“Calibrant [Energy] is \nappreciative of PJM’s engagement during the stakeholder process . . . .”); AEU Comments at 25 (“[Advanced \nEnergy] United commends PJM’s engagement, through the Critical Issue Fast Path process and otherwise.”); \nPJMICC Comments at 2 (PJM Industrial Customer Coalition “wishes to express appreciation to PJM’s \nBoard, Staff, and stakeholders for the intensive communication and collaboration over the past many months \nleading up to the RBP Proposal.”). \n31 July 31, 2026 Post CIFP Workshop – Technical Overview Agenda, PJM Interconnection, L.L.C. (July 31, \n2026), \nhttps://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260731/20260731-\nagenda.pdf [https://perma.cc/2V6H-8CBZ]; August 10, 2026 Post CIFP Workshop – RBP Window \nInformation and Manual Page Turn Agenda, PJM Interconnection, L.L.C. (Aug. 10, 2026), \nhttps://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260810/20260810-agenda.pdf \n[https://perma.cc/9BZY-SX66]; August 28, 2026 Post CIFP Workshop – Technical Overview Agenda, PJM \nInterconnection, L.L.C. (Aug. 28, 2026), https://www.pjm.com/-/media/DotCom/committees-groups/cifp-\nrbp/2026/20260828/20260828-agenda.pdf [https://perma.cc/6BMJ-CEUB]."},{"page":9,"startToken":3316,"endToken":3711,"text":"9 \nadjustments to incorporate intervenors’ suggestions into the RBP proposal in a compliance \nfiling if so ordered by the Commission.32   \nThat said, PJM recognizes that, to the extent any of the intervenors’ suggestions are \nadopted, they must be implemented without undermining other key aspects of a proposal \nthat seeks “to balance urgency with market principles.”33  PJM is appreciative of the \nfeedback and collaboration from intervenors and highlights some of PJM’s responses, in \nthis Answer, to questions raised by intervenors: \n• PJM responds to requests to clarify the role of Electric Distributors in the \nRBP (Answer, Part I.B); \n• PJM responds to requests to clarify proposed Tariff, Attachment DD, \nsection 18.1(d), the opt-out provisions for Electric Distributor zone/areas \nthat address their capacity needs through peak shaving adjustment programs \nthat are codified in state law and that also meet the requirements of Tariff, \nAttachment DD-2 (Answer, Part I.E.1);  \n• PJM responds to the request to clarify the scope of contractual instruments \nthat PJM deems functionally equivalent to and serving the same evidentiary \npurpose as electric and transmission service agreements (Answer, \nPart I.E.2);   \n• PJM responds to the request for clarification that, for purposes of the \nQualifying RBP Offset UCAP MW, incremental new generation or storage \nresource behind a previously registered end-use location should be \npermitted to be used to decrement the RBP procurement target; PJM is \namendable to updating the proposed Tariff, Attachment DD, section \n18.2(b)(vi) as described below (Answer, Part I.E.2); \n• PJM responds to the request for clarification with respect to behind-the-\nmeter generation projects and whether such projects are eligible to provide \n \n32 The Commission has exercised its discretion to permit changes to tariff language identified by the filing \nparty in an FPA section 205 proceeding “meant to clarify . . . existing tariff provisions, eliminate certain \ninconsistencies, and correct typographical and other errors” subject to a compliance filing implementing such \nrevisions.  Cal. Indep. Sys. Operator Corp., 134 FERC ¶ 61,140, at P 1 (2011); id. PP 13-14, 42-43 (accepting \nchanges to tariff language identified by the California Independent System Operator Corporation (“CAISO”) \nin its answer where CAISO agreed with intervenors that changes to the tariff would be consistent with \nCAISO’s intentions and CAISO indicated that it was willing to correct the error; accepting other tariff \nrevisions correcting typographical and other errors). \n33 SEIA Comments at 2."},{"page":10,"startToken":3711,"endToken":4029,"text":"10 \ncapacity as demand response as either Qualifying RBP Offset UCAP or as \nRBP Resources (Answer, Part I.E.2);   \n• PJM responds to requests for clarification of, and would be amenable to \nCPV’s suggested redlines to, Tariff, Attachment DD, section 18.5(f)(i)(2), \nclarifying the RBP gating-criteria provision requiring generation resources \nto provide evidence of 100% site control for each Generating Facility for a \nterm of at least three years (Answer, Part I.F.5); and \n• PJM provides additional clarity concerning when collateral requirements \nneed to be posted and how much would need to be posted in a given \nDelivery Year (Answer, Part I.J.2). \nB. \nThe Role of Electric Distributors in the RBP Is Appropriately Tailored. \nSeveral intervenors requested clarifications concerning the role of Electric \nDistributors in the RBP, and a subset of those intervenors furthermore suggest that the RBP \nproposal exceeds the scope of Electric Distributors’ traditional roles, which are largely \nadministrative in nature.34  PJM submits that the RBP relies on Electric Distributors to play \nan increased reporting and coordination role, but not to exceed the scope of their traditional \nroles.     \nFirst, EKPC alleges that “PJM shifts a significant responsibility and considerable \ndegree of discretion to Electric Distributors.”35  Similarly, Southern Maryland Electric \nCooperative, Inc. (“SMECO”) claims that the role of Electric Distributors in the RBP is \noverly expansive and exceeds the language in the PJM’s Operating Agreement, section \n11.3.3(h) to provide PJM with accounting, customer tracking, load forecasting, and other \ndata.36  But, by SMECO’s own account, the RBP proposal calls for Electric Distributors to \nreport information and act as a go-between—roles that are fundamentally harmonious with \nthe existing role that Electric Distributors have played in PJM.  More specifically, as \n \n34 See, e.g., SMECO Comments at 3-7; AEP Limited Protest at 30-32; EKPC Protest at 35-41. \n35 EKPC Protest at 36.  \n36 SMECO Comments at 4-5."},{"page":11,"startToken":4029,"endToken":4292,"text":"11 \nSMECO explains, the RBP proposal requires that Electric Distributors: (1) communicate \nopt-out request[s] and provide supporting materials to PJM; (2) report capacity offsets and \nprovide supporting evidence to PJM; (3) report state/RERRA-determined allocation; (4) \nreport information that feeds the Electric Distributor zone/area allocation of the RBP \nprocurement Target and LSE daily formula; (5) provide inputs that impact LSE collateral.37 \nSecond, EKPC asserts that PJM’s RBP proposal improperly requires “Electric \nDistributors to effectively set allocation inputs for a Commission-jurisdictional charge. The \nallocation of these inputs impacts cost allocation and credit requirements.”38  These \n“allocation inputs” are, indeed, inputs to PJM forecasts that Electric Distributors already \nprovide.  Ultimately, it is PJM, and, where applicable, PJM states39/Relevant Electric Retail \nRegulatory Authority (“RERRA”)—not the Electric Distributors supplying the underlying \ninputs—that will ultimately determine how such inputs inform cost allocation and credit \nrequirements.   \nThird, SMECO’s claim that PJM has called on Electric Distributors to “develop \nand provide distribution-impact studies for RBP [Distributed Energy Resources (“DER”)] \nAggregation Resources” misconstrues the proposed Tariff language, which states that RBP \nSell Offers from RBP Demand Resources (“DR”) and RBP DER Capacity Aggregation \nResources (“DR/DER”) must be accompanied by applicable Electric Distributor \nrequirements.40  PJM is not imposing, through the RBP proposal, requirements on Electric \n \n37 Id. \n38 EKPC Protest at 35. \n39 The PJM states are: Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North \nCarolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia. \n40 Proposed Tariff, Attachment DD, sections 18.5(f)(i)(12), 18.5(f)(i)(13)."},{"page":12,"startToken":4292,"endToken":4610,"text":"12 \nDistributors to develop new or additional studies or requirements.41  While Electric \nDistributors are, pursuant to the RBP proposal, expected to actively participate in the RBP \nby reporting information and serving as one conduit through which information flows, the \nrole or function of Electric Distributors is not effectively changing.   \nFourth, as described in the July 31 Filing, Electric Distributors perform a reporting \nor administrative role in the RBP and, as American Electric Power Service Corporation \n(“AEP”) correctly notes, do not (to the extent that the same entity or subsidiary thereof \ndoes not occupy another role such as LSE) ultimately bear responsibility for RBP Charges.  \nFinally, PJM directs intervenors to the August 28, 2026 Post-CIFP presentation, which \naddresses RBP implementation and execution details, including the various roles and \nresponsibilities of PJM, Electric Distributors, Transmission Owners, LSEs, states, \nRERRAs, large loads, and other entities in the RBP.42   \nC. \nNothing in Intervenors’ Protests, Comments Call into Question the \nJustness and Reasonableness of PJM’s Proposal to Establish an RBP \nProcurement Target Based on the Observed PJM Region Reliability \nRequirement Shortfall.  \nIn July, the PJM Board of Managers (“PJM Board”) concluded that, in light of the \ndeteriorating resource adequacy conditions in the PJM Region, “a voluntary subscription \nframework would not provide sufficient assurance that capacity equal to the identified \nnear-term shortfall would actually be procured[,]”43 and ultimately directed PJM to file an \n \n41 SMECO Comments at 4-5. \n42 PJM Staff, Reliability Backstop Procurement Execution, PJM interconnection, L.L.C., 5-6 (Aug. 28, 2026), \nhttps://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260828/20260828-item-01---\nreliability-backstop-procurement-execution---pjm-presentation.pdf \n[https://perma.cc/WX4T-UB8T] \n(“August 28, 2026 RBP Execution Presentation”). \n43 Paula Conboy, Chair, PJM Board of Managers, Board Decisional Letter on Critical Issue Fast Path – \nReliability Backstop Procurement and Connect and Manage, PJM Interconnection, L.L.C., 1 (July 27, 2026), \nhttps://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-disclosures/2026/20260727-board-"},{"page":13,"startToken":4610,"endToken":4945,"text":"13 \nRBP proposal that would procure for the identified near-term shortfall of 6,831.3 MW \n(UCAP) of PJM’s Regional Transmission Organization (“RTO”) Reliability Requirement.   \nSeveral protestors assert that, rather than procuring for the observed, near-term \nshortfall of 6,831.3 MW (UCAP), the RBP should be based on the Joint Electric \nDistribution Companies and DCC RBP proposal (“Coalition RBP Proposal”), which is \ncentered on a voluntary, subscription-based procurement wherein LSEs would voluntarily \nopt in to the procurement on behalf of their large load customers rather than being allocated \ncosts by PJM.44  It is worth noting, however, that DCC—an author of the Coalition RBP \nProposal—was not among them.  In fact, DCC filed in support of and urged the \nCommission to accept PJM’s RBP proposal, while acknowledging that the RBP proposal \nfiled by PJM on July 31 “is not the framework DCC proposed.”  According to DCC, \n“[g]iven the urgency of PJM’s resource adequacy challenge, DCC supports moving \nforward with the RBP as a limited, one-time backstop[,]” particularly as “the filed proposal \nincorporates several important elements of the [Coalition RBP Proposal].”45   \nThe Initial RBP Target of 6,831.3 MW (UCAP) represents a measured approach to \naddressing an urgent challenge that reflects careful consideration of many competing \ninterests, as well as the role of the RBP as just one stop-gap measure in the context of more \nholistic, permanent solutions to the capacity market challenges that PJM faces today.  In \naccordance with the NEDC/PJM Governors’ Principles, PJM is on a path toward returning \n \ndecisional-letter-on-cifp-reliability-backstop-procurement-and-connect-and-manage.pdf \n[https://perma.cc/V9Z7-83AH]. \n44 See, e.g., JCA Protest at 30-32; EKPC Protest at 8-9, NOVEC Protest at 25, NYU Institute Comments \nat 23. \n45 DCC Comments at 2.  Likewise, intervenor Exelon Corporation, an Electric Distributor and one of the \nauthors of the Coalition RBP Proposal, did not file comments or protests in response to the July 31 Filing.  \nPJM Interconnection, L.L.C., Motion to Intervene of Exelon Corporation, Docket No. ER26-3380-000 \n(Aug. 4, 2026)."},{"page":14,"startToken":4945,"endToken":5237,"text":"14 \nto market fundamentals as soon as possible.46  In the meantime, the RBP proposal is just \none piece of a multi-pronged response that is still in progress.  The RBP proposal is not a \none-stop solution to all the challenges in PJM’s capacity market.   \nThe RBP proposal will address the immediate capacity shortfall by procuring \nsupply that is capable of coming online quickly, has a high level of certainty of being built, \nand can dependably provide capacity through the 2042/2043 Delivery Year, while PJM \nsimultaneously works toward “reform[ing] the capacity market to ensure long-term \nviability and prevent consumers from bearing excessive ongoing costs[.]”47  In other \nwords, it will kick-start the ongoing process of working towards addressing capacity \nshortfalls.   \nAs Dominion’s protest and comments state, “[t]he RBP is not an answer to PJM’s \nresource adequacy problem but is a necessary stop-gap solution to stabilize the region and \nallow for a more holistic review of the markets.”48 The procurement target reflects the fact \nthat the RBP is intended to be a bridge, not a permanent, long-term solution. \n1. \nWhere LSEs have, in recent history, not independently procured \nsufficient capacity despite forecasted demand growth, there is good \nreason to find that a voluntary, subscription-based procurement will \nnot ensure sufficient capacity to cover the shortfall. \nSupport for an RBP based on a voluntary, subscription-based or opt-in model, in \nessence, supports more of the status quo, even when the status quo has not been working.  \nIn PJM, it has long been the case that LSEs, and/or large loads served by those LSEs, may \nvoluntarily enter into bilateral arrangements with suppliers of new capacity, without \n \n46 NEDC/PJM Governors’ Principles at 1. \n47 Id. \n48 Dominion Partial Protest and Comments at 3."},{"page":15,"startToken":5237,"endToken":5586,"text":"15 \nintervention from PJM.  This avenue for procuring capacity was open to the relevant parties \nlong before the last two Base Residual Auctions (“BRA”) cleared short and, in fact, the \nability to bilaterally contract for capacity even predates the advent of the RPM.  \nNevertheless, the fact of the matter remains, voluntary arrangements for new capacity have \nnot met that demand, and such arrangements have only just begun to gain traction as the \nprojected September date for the RBP nears.  Only in recent months, spurred by recent \nmarket conditions, along with this RBP proposal featuring a specific procurement target \nand PJM’s separate interim resource adequacy service (“IRAS”) proposal, have parties, \nincluding LSEs and/or the large loads they serve, begun to actively express greater interest \nin entering into agreements for meaningful amounts of new capacity that would even make \na dent in the shortfall.49   \nIn fact, despite the longstanding ability of LSEs, and/or the large loads served by \nLSEs, and suppliers of capacity, to enter into voluntary arrangements for new capacity, \nPJM cleared short of the PJM Region Reliability Requirement in the 2028/2029 BRA for \na second consecutive year.50  More specifically, the 2028/2029 BRA cleared 6,831.3 MW \nshort of the RTO Reliability Requirement,51 up from the 6,516.6 MW shortfall observed \n \n49 Anna Flávia Rochas, PJM capacity market woes spur activity bilateral power deals, Reuters (Aug, 25, \n2026), https://www.reuters.com/business/energy/pjm-capacity-market-woes-spur-activity-bilateral-power-\ndeals--reeii-2026-08-26/; PSEG offers large load supply proposals in PJM’s bilateral contracting process, \nUtility Dive (Aug. 5, 2026), https://www.utilitydive.com/news/pseg-data-center-pjm-bilateral-contract-\nreliability/827045/ [https://perma.cc/FLF3-MSLY].  Furthermore, entering into such bilateral arrangements \nmay ultimately insulate parties from the recently proposed IRAS mechanism, if that mechanism is accepted \nby the Commission. \n50 July 31 Filing, Transmittal Letter at 7 (citing 2028/2029 Base Residual Auction Report, PJM \nInterconnection, L.L.C., 3 (July 14, 2026), https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-\nauction-info/2028-2029/2028-2029-bra-results-report.pdf \n[https://perma.cc/A53K-TXXY] \n(“2028/2029 \nBRA Report”)). \n51 2028/2029 BRA Report at 3."},{"page":16,"startToken":5586,"endToken":5882,"text":"16 \nin the 2027/2028 BRA.52  The 2028/2029 BRA attracted less new capacity, even as the \nreliability requirement grew from 146,105 MW to 152,400 MW (UCAP). \nIn January 2026, the NEDC/PJM Governors’ Principles implicitly recognized the \nneed for a procurement target, as it would certainly not have been necessary to call for a \nreliability backstop auction to be held no later than September 2026 in the first place, were \nLSEs, the large loads they serve, and suppliers of new capacity already voluntarily entering \ninto arrangements for capacity in quantities sufficient to address the shortfall.  Furthermore, \nalthough PJM originally proposed a longer bilateral contracting period prior to the \ncommencement of the RBP auction, for the reasons outlined above, PJM’s instant proposal \nis cognizant of the NEDC/PJM Governors’ Principles requesting a backstop auction by no \nlater than September 2026. \nMoreover, the facts do not support intervenors’ suggestions that a voluntary, \nsubscription-based model would adequately cover the capacity shortfall.  Thus, the PJM \nBoard reasonably concluded, based on those facts, that a voluntary, subscription-based \nframework would not procure sufficient new capacity to meet demand and, in fact, would \nbe highly likely to fail to cover that shortfall.53   \nIn its protest, Northern Virginia Electric Cooperative, Inc. (“NOVEC”) counters \nthat “even if [a voluntary, subscription-based model] procured less than the total shortfall, \nthat should not be considered a failure when considered in the context of the” Coalition \nRBP Proposal.54  But accepting such a counterargument would effectively contradict the \n \n52 2027/2028 Base Residual Auction Report, PJM Interconnection, L.L.C., 3 (Dec. 17, 2025), \nhttps://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/2027-2028/2027-2028-bra-\nreport.pdf [https://perma.cc/TA3Y-95AX].  \n53 July 31 Filing, Transmittal Letter at 21-22. \n54 NOVEC Protest at 25."},{"page":17,"startToken":5882,"endToken":6187,"text":"17 \nfundamental core reliability goal of the RBP to acquire the capacity shortfall the region is \nalready expected to experience due, in part, to individual, voluntary business decisions of \ncontracting sellers and buyers of capacity. \n2. \nThe procurement target represents a conservative approach based \non known, measurable, and observable metrics, which PJM has \nshown to be just and reasonable. \nA number of intervenors assert that the procurement target may over procure for \ncapacity or has not been fully supported.55  The Initial RBP Target is based on a known, \nmeasurable, and readily observable capacity shortfall that is not in dispute.  Compared to \nthe recent resource adequacy forecasts projections, a 6,831.3 MW procurement target is \nconservative.  In fact, as explained in the July 31 Filing, “the primary purpose of the RBP \nTarget is to determine how much UCAP MW is needed to meet the reliability requirement \nshortfall without over-procuring.”56 \n Indeed, as the Commission recently noted in a June 2026 order to show cause, \n“[w]hile we are encouraged by the implementation of [the RBP and other] processes to \nensure resource adequacy and faster interconnection and ongoing stakeholder discussions, \nwe remain concerned that these efforts may fall short in light of generator retirements and \ntightening supply conditions.”57   \nFirst, PJM, the North American Electric Reliability Corporation (“NERC”), and \nother industry experts on the matter project that the capacity shortfall in the next 10 years \nwill be on an order of magnitude of four to nine times the 6,831.3 MW shortfall.  PJM’s \n2025 Long-Term Load Forecast projects a peak load growth of 32 gigawatts (“GW”) from \n \n55 See, e.g., NYU Institute Comments at 23-25; ODEC Comments at 5. \n56 July 31 Filing, Transmittal Letter at 52. \n57 PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, at P 103 (2026) (emphasis added)."},{"page":18,"startToken":6187,"endToken":6544,"text":"18 \n2024 to 2030, with all but 2 GW coming from data centers.  The summer peak is expected \nto reach 222 GW by 2036.  The PJM Board has warned that new large load demand could \nrise by about 70 GW by 2038, even as roughly 15 GW of generation has retired in the PJM \nfootprint since 2022.  Similarly, NERC’s 2026 forecast predicts “high”58 capacity risk by \n2029.  In this context, the approximately 6.8 GW procurement target is absorbed many \ntimes over. \nSecond, because the procurement target is deliberately conservative, despite \nassertions by some intervenors to the contrary, recent downward adjustments to near-term \nforecasted large load demand do not suggest that the need for new capacity has eroded to \nthe point that 6,831.3 MW (UCAP) of new capacity risks overstating the target.  To the \nextent that forecasted large load demand may be adjusted down, the expected increase in \ndemand over the foreseeable future still far exceeds 6,831.3 MW.  Additionally, while the \nprocurement target is based on the BRA shortfall for the 2028/2029 Delivery Year, the \nRBP will procure resources with in-service dates up until the 2032/2033 Delivery Year.  \nAllowing procurement of capacity beyond the initial 2028/2029 Delivery Year decreases \nthe risk of over procurement.   \nThird, the 6,831.3 MW shortfall is in and of itself already adjusted to reflect recent \nimprovements to PJM’s forecasting methods.59  The 6,831.3 MW figure already \nincorporates forecast updates and improved vetting of requested adjustments for data \n \n58 2025 Long-Term Reliability Assessment, North American Electric Reliability Corporation, 8 (Jan. 2026), \nhttps://www.nerc.com/globalassets/our-work/assessments/nerc_ltra_2025.pdf \n[https://perma.cc/BSH7-\n7ALZ]; id. at 12 (“An assessment area is determined as High Risk when established resource adequacy targets \nor requirements are not met or when probabilistic or deterministic energy analyses find that planned resources \nproduce shortfalls resulting in unserved energy or load loss exceeding criteria for baseline resource \nadequacy.”). \n59 PJM’s Updated 20-Year Forecast Continues To See Significant Load-Term Load Growth, PJM Inside \nLines \n(Jan. \n14, \n2026), \nhttps://insidelines.pjm.com/pjms-updated-20-year-forecast-continues-to-see-\nsignificant-long-term-load-growth/ [https://perma.cc/W3UY-F9HE]."},{"page":19,"startToken":6544,"endToken":6736,"text":"19 \ncenters and large loads including, for example, an updated load forecast for summer 2026 \nthat predicted a drop in peak electricity use attributed to large loads (-0.7%), compared to \nthe PJM 2025 Long-Term Load Forecast Report.60  Nevertheless, as the Summer Peak and \nWinter Peak graphs from PJM’s 2026 Load Forecast Report makes clear, while slight \ndownward adjustments from the 2025 forecast were made to reflect the updated 2026 \nSummer and Winter Peak forecasts,61 PJM continues to expect significant and \nunprecedented growth, largely arising from large load demand. \n \nFourth, the RBP proposal permits the initial 6,831.3 MW target to be further \nadjusted down to reflect additional new capacity brought on to serve new load and certain \nopt-outs.  Once additional new capacity and opt-outs are accounted for, the Final RBP \nTarget will be lower than the Initial RBP Target of 6,831.3 MW.  In other words, while the \n \n60 See id. \n61 PJM Resource Adequacy Planning Department, 2026 PJM Load Forecast Report, PJM Interconnection, \nL.L.C., 9 (Jan. 14, 2026), https://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2026-\nload-report.pdf [https://perma.cc/6BPF-LJYA]."},{"page":20,"startToken":6736,"endToken":7015,"text":"20 \ninitial procurement target is a fixed, known quantity set by the recent 2028/2029 Delivery \nYear BRA results, the final procurement target provides the flexibility to reduce that initial \nshortfall through Qualifying RBP Offset UCAP MW or opt-outs.  This means that rather \nthan being required to affirmatively opt in to the RBP, as would be the case under a \nvoluntary, subscription-based model, PJM’s RBP proposal preserves opportunities to opt \nout.  Thus, once reductions for Qualifying RBP Offset UCAP MW and opt-outs are \naccounted for, the Final RBP Target will be lower than the Initial RBP Target of \n6,831.3 MW.   \nThe risk of over-procurement is therefore highly unlikely based on the facts and \ncircumstances that PJM faces today, as well as the design of the proposed RBP Target.  \nFurthermore, PJM proposes to procure for the known and measurable shortfall reflected in \nthe 2028/2029 BRA in recognition that the value is not in dispute and that the RBP is not \nintended to be the one and only solution to the resource adequacy challenges facing the \nPJM Region today. \n3. \nThe procurement target need not contain a locational requirement. \nSome protestors assert that the procurement target should include a locational \nrequirement, and/or account for the needs of specific LSEs and/or large loads.62  Calls to \ndevelop a more granular RBP procurement target are misguided.   \nAs PJM’s July 31 Filing notes, requiring more granularity by including locational \nparameters or requiring subsequent, periodic adjustments to the target only risks skewing \nresults.  Importantly, inclusion of a speculative locational parameter at this point would \nignore the fact that:  \n \n62 See, e.g., EKPC Protest at 31-33; JCA Protest at 28-29."},{"page":21,"startToken":7015,"endToken":7357,"text":"21 \nPJM’s interconnection process ensures the initial deliverability of \nnew capacity to the RTO.  Going forward, the PJM Regional \nTransmission Expansion Plan (“RTEP”) process annually studies \nand addresses any transmission upgrades needed to ensure the \nongoing deliverability of capacity resources.  Load deliverability is \nalso assessed as part of the RTEP process, which will identify \ntransmission needs as load patterns change.63   \nIn short, inclusion of a speculative 15-year forward locational capacity requirement \nwould simply ignore actual PJM’s system topology during the term of the RBP \ncommitment.  Such an approach disregards the role of PJM’s interconnection and planning \nprocess, which studies deliverability of capacity resources to load throughout the PJM \nRegion based on actual system locational needs.64 \nAdditional granularity or updates are also unnecessary in light of the role of the \nRBP as a stop-gap solution that procures for the RTO-wide shortfall while PJM \nsimultaneously continues to make progress on a broader, holistic review of its capacity \nmarket, the RPM, to identify durable, more permanent solutions to concerns stemming \nfrom large load additions.65  This ongoing holistic review is in line with the NEDC/PJM \nGovernors’ Principles, which urged PJM to “embark on a stakeholder process to reform \nthe capacity market to ensure long-term viability and prevent consumers from bearing \nexcessive ongoing costs,” with an ultimate goal of returning PJM to market \nfundamentals.66  The Initial RBP Target of 6,831.3 MW is a conservative and a rough \n \n63 July 31 Filing, Affidavit of Ms. Danielle Croop on Behalf of PJM Interconnection, L.L.C. (Attachment C) \n¶ 9 (“Croop Aff.”). \n64 Id. ¶ 9.  \n65 See Powering Reliability Through Market Design: Addressing Rising Demand and Constrained Supply, \nand Stimulating Investment to Support Durable Reliability (May 9, 2026), https://www.pjm.com/-\n/media/DotCom/library/reports-notices/special-reports/2026/20260506-powering-reliability-through-\nmarket-design.pdf [https://perma.cc/3W8Z-M4TQ]. \n66 NEDC/PJM Governors’ Principles at 1; see also CIFP Reliability Backstop Procurement – PJM Proposal, \nPJM Interconnection, L.L.C., 1 (June 11, 2026), https://www.pjm.com/-/media/DotCom/committees-\ngroups/cifp-rbp/2026/20260611/20260611-item-04a---pjm-reliability-backstop-proposal---post-meeting-"},{"page":22,"startToken":7357,"endToken":7777,"text":"22 \nestimate; it is not intended to identify, with exacting precision, the full scope each PJM \nzone/area’s capacity needs and, indeed, as noted above, guards against over-procurement.  \nThe Commission has never required procurement targets, particularly where they are \nspecifically designed to be conservative, to be calculated with exacting precision or \ncontinuously adjusted to reflect updated information.67 \nD. \nRBP Offsets Should Neither Be Expanded to Include Additional Types of \nCapacity nor Revised to Account for Subsequent Reductions in Demand.  \nA number of intervenors critique the proposed parameters for Qualifying RBP \nOffset UCAP MW, arguing that Qualifying RBP Offset UCAP MW should be expanded \nto permit additional capacity to be decremented from the Initial RBP Target or otherwise \nallow for adjustments.  The parameters for Qualifying RBP UCAP MW were thoroughly \nsupported in the July 31 Filing.68  As noted above, the Commission has never required \nprocurement targets to be calculated with exacting precision or continuously updated to be \njust and reasonable.   \n \nmaterials.pdf [https://perma.cc/X7T7-5RPB] (“2026 PJM CIFP Proposal”) (providing background on \nstakeholder engagement). \n67 See, e.g., PJM Interconnection, L.L.C., 128 FERC ¶ 61,157, at P 77 (2009) (denying intervenor proposal \n“that [Interruptible Load for Reliability] capacity be determined prior to the third incremental auction so that \nthis last auction would adjust total capacity procured such that PJM ultimately procured the targeted amount \nof capacity.”  Noting that “[t]his argument, however, does not go to the question of whether PJM’s proposal \nin this case is just and reasonable.  It is true that there may be more than one just and reasonable means of \naccommodating short lead-time resources in PJM's auctions, and in determining whether to accept PJM's \nfiling, the Commission must only determine that PJM’s proposed solution is just and reasonable, not that it \nis superior to other possible solutions.  Interruptible Intervenors have not demonstrated that PJM’s proposal \nis unjust and unreasonable, and we therefore reject their request for rehearing.” (footnotes omitted)); see also \nMidcontinent Indep. Sys. Operator, Inc., 189 FERC ¶ 61,108 (2024) (accepting proposed Target MW Value, \na projected new interconnection MW quantity enabled by the Joint Targeted Interconnection Queue Portfolio \nidentified by the RTOs, which was a conservative estimation of the appropriate amount of generation to \nparticipate in the Joint Targeted Interconnection Queue Portfolio without risking oversubscription), order on \nreh’g, 191 FERC ¶ 61,231 (2025), appeals appending sub nom. Ark. Pub. Serv. Comm’n v. FERC, \nNos. 25-60127, et al. (5th Cir. Mar. 17, 2025). \n68 July 31 Filing, Transmittal Letter at 35-44."},{"page":23,"startToken":7777,"endToken":8070,"text":"23 \n1. \nPJM correctly concluded that only new capacity should be eligible \nto serve as Qualifying RBP Offset UCAP MW and decremented \naccordingly from the RBP procurement target. \nSome intervenors suggest that not decrementing existing capacity, already secured \nthrough existing bilateral arrangements with large loads from the RBP procurement \ntarget—either by treating that existing capacity as Qualifying RBP Offset UCAP MW or \nthrough an opt-out provision—risks “disrupting existing commercial arrangements.”69  As \none intervenor observes, “[t]his does not account for new load that has entered into a \nbilateral [Power Purchase Agreement (“PPA”)] with an existing generation resource.”70 \nFirst, the entire premise that not decrementing the RBP procurement target by the \namount of capacity associated with an “existing generation resource” that has entered into \na bilateral PPA with new load would “disrupt” existing commercial arrangements is \nspecious at best.  Whether the RBP procurement target is reduced by the capacity \nrepresented in such bilateral PPAs has no direct bearing on the commercial arrangement \nitself.  The RBP does not abrogate, interfere with, or disrupt the agreement.   \nSecond, the purpose of the RBP is to procure new capacity provided by new \ngeneration resources and other capacity resources.  There has been insufficient new \ncapacity to match the demand created by new load that has been coming online at a pace \nand quantity that has never been matched before.  As OPSI notes, this approach “helps \nensure that bilateral offsets and RBP procurements result in a genuine increase in regional \ncapacity rather than simply shifting existing commitments among procurement \nmechanisms.”71  The fact that new load has contracted with an existing generation resource \n \n69 See, e.g., Talen Request for Clarification at 4; Amazon Comments at 3. \n70 Id. at 4. \n71 OPSI Comments at 3."},{"page":24,"startToken":8070,"endToken":8328,"text":"24 \nsimply means that the existing generation resource is no longer serving existing load.  The \nshortfall thus remains—a shortfall that would not have existed without the demand created \nby large loads.  Indeed, the existing resources Amazon Energy LLC (“Amazon”) refers to \nin its comments72 were already accounted for in the supply curve for the 2028/2029 BRA, \nwhich factored into the 6,831.3 MW shortfall the initial RBP procurement target is looking \nto procure.  Allowing such existing generation to offset this target would simply not \ncontribute to closing the shortfall. \nThus, far from “double charging large loads for capacity,” requiring Qualifying \nRBP Offset UCAP MW to be new capacity matched with new load ensures that an already \nconservative Initial RBP Target is only decremented to account for new capacity and that \nnew load does not simply protect itself from allocation of RBP Charges by purchasing \nexisting capacity resources and leaving fewer available resources for residential and \nexisting commercial customers. \nTo be deemed new capacity that may serve as Qualifying RBP Offset UCAP MW, \ncapacity must have neither previously received a commitment in the RPM nor been \npreviously committed in a Fixed Resource Requirement (FRR”) plan, as of the beginning \nof the RBP, which is anticipated to occur in or around September 2026.73  Existing capacity \nthat is already the subject of bilateral contracts is not new capacity, even where that \ncapacity has entered into bilateral contracts with new load.   \n \n72 Amazon Comments at 3. \n73 July 31 Filing, proposed Tariff, Attachment DD, section 18.2(a)."},{"page":25,"startToken":8328,"endToken":8621,"text":"25 \n2. \nA just and reasonable RBP proposal does not require PJM to \ndecrement the Initial RBP Target to account for near-term \nreductions in forecasted demand.  \nSeveral intervenors suggest that the RBP procurement target should be further \nadjusted to account for withdrawals of prospective large load during the RBP procurement \nwindow.  According to those intervenors, the quantity of withdrawn demand should be \ndecremented from the Region-wide RBP Target.74  But even if there have been some \nwithdrawals of prospective large loads—as reflected in the slight reduction in large load \ndemand captured in the most recent PJM load forecast, that forecast nevertheless continues \nto predict steep, exponential load growth in demand.  Thus, a just and reasonable RBP \nproposal need not further decrement the RBP procurement target to account for specific, \nrecent large load withdrawals. \nE. \nPJM Addresses Several Intervenor Requests for Clarification to the \nProposed Opt-Outs. \n1. \nPJM is providing several clarifications to the peak shaving \nadjustment opt-out in response to requests from intervenors. \nBase Power, NJ BPU, and Advanced Energy United request clarifications \nconcerning the proposed opt-out for Electric Distributor zone/areas that address their \ncapacity needs through peak shaving adjustments.  PJM addresses those requests below. \nFirst, both NJ BPU and Base Power request clarification about timing of electing \nthe opt out for qualifying peak shaving adjustment programs.75  PJM confirms that the \nsubmission of the full peak shaving adjustment plans would not be needed at the time of \nan election to opt out of the RBP.  Specifically, peak shaving adjustment plans for the \n2028/2029 Third Incremental Auction can be submitted as late as September 2027 in \n \n74 See, e.g., OPSI Comments at 3-4; JCA Protest at 10-12. \n75 NJ BPU Comments at 6-7; Base Power Comments at 2, 6-8."},{"page":26,"startToken":8621,"endToken":8950,"text":"26 \naccordance with the existing rules specified in Tariff, Attachment DD-2.76  PJM will \nsimply require an Electric Distributor that elects to opt out of the RBP that a peak shaving \nadjustment plan will be submitted in accordance with the requirements set forth in Tariff, \nAttachment DD-2 at the time it makes the opt-out request, which will be due within three \nweeks from the commencement of the RBP (i.e., if the RBP commences September 30, the \nrequests would be due by October 21).   \nBase Power also requests that PJM clarify “that the peak shaving decrement is not \ndiscounted and will have a 1:1 ratio; in other words, every 1 MW of peak-shaving \nidentified by an Electric Distributor will result in 1 MW decremented from the Initial RBP \nTarget, with no adjustments.”77  PJM also confirms that every MW of peak-shaving \nadjustment, converted into UCAP terms, to opt out of RBP will be used to offset the final \nRBP procurement target on a 1:1 ratio.  This approach also accommodates state policy in \nthe course of determining the appropriate Final RBP Target.  Third, Base Power suggests \nthat the proposed Tariff language, Attachment DD, section 18.1(d) should be revised to \nremove the words “up to” from the proposed language: \nThe Initial RBP Target shall be further decremented, if requested by \nan Electric Distributor, by up to the associated MW quantity of load \nthat participates in a peak shaving adjustment program where such \nElectric Distributor’s zone/area addresses their capacity needs \nthrough peak shaving adjustment programs that are codified in state \nlaw \nand \nthat \nalso \nmeet \nthe \nrequirements \nof \nTariff, \nAttachment DD-2.78 \n \n76 Tariff, Attachment DD-2 (“Peak Shaving Adjustment plan shall be submitted to the Office of the \nInterconnection no later than 10 Business Days prior to September 30 to be effective for the next PJM load \nforecast update”). \n77 Base Power Comments at 2. \n78 July 31 Filing, proposed Tariff, Attachment DD, section 18.1(d)."},{"page":27,"startToken":8950,"endToken":9252,"text":"27 \nPJM does not believe that the “up to” language should be removed from the proposed Tariff \nprovision.  The words “up to” signify that PJM may, to the extent the associated MW \nquantity of load participating in a peak shaving adjustment program does not meet the \nrequirements of the opt-out, determine not to decrement the RBP procurement target by \nthat quantity of MW.  It is also possible that an additional party already has a bilateral \nagreement which would offset the target, thus requiring less peak shaving adjustment to \nmeet the total target.  Without the words “up to” in the proposed Tariff language, there \ncould be confusion as to where to credit the additional non required reduction against the \nRBP procurement target. \n \nLastly, Advanced Energy United raises concerns that “a load that successfully \nqualifies for the RBP opt-out [through participation in a qualifying peak shaving \nadjustment program] could nonetheless find itself subject to IRAS curtailment.”79  \nAdvanced Energy United raises this concern in response to the statement, in the July 31 \nFiling, that “‘even if the Electric Distributor zone/area qualifies for and receives an opt-out \nfrom the RBP, the load in that zone/area may be subject to load reduction under the \nforthcoming proposal to implement an IRAS.’”80  To the extent that peak shaving \nadjustment interacts with IRAS, such issues are outside the scope of this proceeding and \nwill be separately addressed in the IRAS proceeding in Docket No. ER26-3515-000.  \n2. \nClarification regarding evidence required to satisfy Qualifying RBP \nOffset UCAP MW requirements set forth in proposed Tariff, \nAttachment DD, section 18.2. \nSeveral intervenors seek clarifications regarding the evidence that may support \nQualifying RBP Offset UCAP MW.  First, Tract Holding Company I, LLC (“Tract”) seeks \n \n79 AEU Comments at 6. \n80 Id. (quoting July 31 Filing, Transmittal Letter at 46)."},{"page":28,"startToken":9252,"endToken":9528,"text":"28 \nclarification with respect to the requirement that Qualifying RBP Offset UCAP MW be \naccompanied by an “executed electric service agreement or transmission service \nagreement.”81  According to Tract, other “functionally equivalent agreements that serve \nthe same evidentiary purpose as electric and transmission service agreements” should \nsatisfy the evidentiary requirements for Qualifying RBP Offset UCAP MW.82 Tract notes, \nfor example, that new load customers may:  \nhave executed transmission security agreements, construction letters \nof authorization, or similar agreements have undertaken binding \ncontractual and financial commitments functionally equivalent to \nthose assumed under standard electric service or transmission \nservice agreements.  In each case, the customer has demonstrated a \ngenuine, non-speculative commitment to achieve commercial \noperation within a defined timeframe; the sole relevant distinction \nlies in the particular contractual instrument through which that \ncommitment has been formalized.83 \nPJM agrees that it is the binding nature of contractual agreements that supports a \nnon-speculative commitment to achieve commercial operation within a defined timeframe, \nnot the format in which the contractual instrument has been formalized.  PJM clarifies that, \nin the implementation of this proposed Tariff provision, it will also consider contractual \ninstruments that PJM deems functionally equivalent to and serving the same evidentiary \npurpose as electric and transmission service agreements.   \nSecond, Calibrant Energy requests clarification with respect to whether behind-the-\nmeter generation projects are eligible to provide capacity as demand response either as \nQualifying RBP Offset UCAP or as RBP Resources.84  For reasons discussed above and in \n \n81 July 31 Filing, proposed Tariff, Attachment DD, section 18.2(c). \n82 Tract Request for Clarification or Limited Protest at 4. \n83 Id. at 9. \n84 Calibrant Request for Clarification at 2."},{"page":29,"startToken":9528,"endToken":9819,"text":"29 \nthe July 31 Filing, decrements to the RBP procurement target based on Qualifying RBP \nOffset UCAP MW account for recent new capacity matched to new load.  Likewise, as \npreviously discussed, PJM’s requirements and gating criteria for RBP Resources requires \nresources to meet stringent requirements to be eligible to receive potential rewards in the \nprocurement and price certainty up to a term of 15 years.  To be clear, the eligibility \nrequirements for Qualifying RBP Offset UCAP and RBP Resources are not the same.  To \nthe extent that generation provides capacity meeting the qualifications set forth in either \nproposed Tariff, Attachment DD, section 18.2(c), to provide Qualifying RBP Offset UCAP \nMW, or the qualifications in proposed Tariff, Attachment DD, section 18.5, to serve as \nRBP Resources, that capacity can be said to contribute to addressing the resource adequacy \nshortfall. \nThird, Voltus requests clarification that, for purposes of the Qualifying RBP Offset \nUCAP MW, incremental capacity comprised of new generation or storage resource behind \na previously registered end-use location should be permitted to be used to decrement the \nRBP procurement target.85  PJM agrees with Voltus that such an approach “hews closely \nto language PJM has used later in the proposed tariff while defining RBP resource \neligibility.”86  To that end, PJM is amendable to updating the proposed Tariff, Attachment \nDD, section 18.2(b)(vi) as follows: \n(vi) Planned Demand Resource or Planned DER Capacity \nAggregation Resources, as described in the RAA, Schedule 6 and \nSchedule 6.2, where such incremental capacity are not reliant on \nlocations which previously provided capacity unless such previous \nlocation represents additional capacity resulting from an investment \nin new generation or new storage resources at that location. \n \n \n85 Voltus Comments at 9. \n86 Id."},{"page":30,"startToken":9819,"endToken":10110,"text":"30 \n3. \nPJM understands that ODEC’s rates are not subject to regulation \nof the Virginia State Corporation Commission. \nOld Dominion Electric Cooperative (“ODEC”) raises concerns that, as an electric \ncooperative with member distribution cooperatives in Virginia—a state in which “electric \ncooperatives operate under a regulatory framework that includes oversight of rates and \nservices by the Virginia State Corporation Commission”87—ODEC and its member \ndistribution cooperatives may not qualify for the opt-out applicable to “Electric \nDistributor’s zone/area has rates that are not regulated by the states and is unable to address \ncost allocation associated with capacity procured in the backstop.”88  ODEC, in its \ncomments, notes that it “believes the opt-out was intended to provide a reasonable \nsafeguard for smaller utilities, including electric cooperatives and municipal utilities, that \ncould face disproportionate exposure to Reliability Backstop Procurement obligations.”89   \nAs PJM described in the July 31 Filing, this narrow opt-out was designed to address \na limited regulatory gap faced by cooperatives and municipal utilities whose rates are not \nregulated by the states.90  To the extent that cooperatives and municipal utilities’ rates are \nnot governed by a state regulatory authority that would be responsible for addressing the \npotential reallocation of RBP Costs to either large loads or other zone/areas within the state, \nthere is risk that those cooperatives and municipal utilities’ customers would be at risk of \nabsorbing the costs of an “overbuy” if a particular large load fails to materialize.91  Thus, \nthe proposed opt out should appropriately be limited only to those Electric Distributors that \n \n87 ODEC Comments at 7. \n88 July 31 Filing, proposed Tariff, Attachment DD, section 18.1(d). \n89 ODEC Comments at 8. \n90 July 31 Filing, Transmittal Letter at 45. \n91 Id."},{"page":31,"startToken":10110,"endToken":10398,"text":"31 \nare not regulated by the state.  To the extent that “ODEC is the LSE for its member \ncooperatives” and “ODEC is not subject to rate regulation by state commissions,”92 ODEC \nwould qualify as an Electric Distributor that is not subject to regulation by the state and \nmay elect to opt out of the RBP. \nF. \nPJM’s Procurement Process Is Just and Reasonable. \nSeveral protests challenge aspects of PJM’s proposed procurement process under \nthe RBP.  Specifically, those protests assert that the proposal to procure RBP Resources \nfor a fixed term of up to 15 years is too long, the $555/MW-day (UCAP) cap on the \nmaximum willingness to pay is too low, too high, or should not exist, and/or that the \nprocurement, presently targeted to take place at the end of September 2026, should be \ndelayed.  None of these arguments undermine the justness and reasonableness of PJM’s \nRBP proposal.  \n1. \nProcuring RBP Resources for a fixed term of up to 15 years is just \nand reasonable and not unduly discriminatory or preferential.  \nSome intervenors assert that the RBP proposal is unjust and unreasonable, because \nthe RBP aims to obtain commitments of new RBP UCAP MW from RBP Resources for a \nfixed term of up to 15 years—starting as early as the 2028/2029 Delivery Year and ending \nwith the 2042/2043 Delivery Year, with commitment terms of RBP Resources scheduled \nto commence service after the 2028/2029 Delivery Year shortened by a commensurate \nnumber of years and ending in the 2042/2043 Delivery Year.   \nAs noted in the July 31 Filing, the fixed, maximum 15-Delivery Year term is \ninformed by the NEDC/PJM Governors’ Principles, which expressly sought “15-year price \n \n92 ODEC Comments at 9."},{"page":32,"startToken":10398,"endToken":10744,"text":"32 \ncertainty for new capacity resources[]”93 to provide “[r]evenue [c]ertainty to [n]ew \n[g]eneration[.]”94  Nevertheless several intervenors assert that procuring for a fixed term \nof up to 15 years is unjust and unreasonable.95  Those arguments are without merit. \nAccording to the Joint Consumer Advocates (“JCA”), procuring RBP Resources \nthrough a central procurement for a fixed 15-year term, ending in the 2042/2043 Delivery \nYear, is internally inconsistent with PJM’s assertion that Qualifying RBP Offset UCAP \nMW, which may decrement the RBP procurement target, may be supported by bilateral \narrangements for new capacity resources for terms as short as five years.96   \nThe JCA’s protest draws a false equivalence, erroneously comparing the \nrequirement that bilateral arrangements supporting Qualifying RBP Offset UCAP MW \ncontract for a minimum of five Delivery Years, with the requirement that resources \nprocured through the RBP offer commitments for RBP UCAP MW for a fixed period of \n15 Delivery Years.  Bilateral arrangements for new capacity are distinguishable from the \nRBP procurement mechanism.  Parties that enter into bilateral arrangements are neither \nsimilarly situated to the suppliers that voluntarily submit offers in the RBP, with \nPJMSettlement as the counterparty to such offers, nor to the LSEs and large loads that are \nultimately allocated cost responsibility for RBP UCAP MW. \n \n93 NEDC/PJM Governors’ Principles at 1; see also Tariff, Attachment DD, section 16.4(a) (“The Reliability \nBackstop Auction shall obtain commitments of additional Generation Capacity Resources (or, as applicable, \nadditional Base Load Generation Resources) for a term of up to fifteen (15) Delivery Years.”). \n94 NEDC/PJM Governors’ Principles at 1. \n95 See, e.g., JCA Protest at 14; ICC Comments at 4; AEP Limited Protest at 6, 28-30; Blue Ridge Comments \nat 3. \n96 JCA Protest at 14 (“The [proposed RBP] design defeats itself by requiring the purchase of longer-term \nresources while constraining the participation of shorter-term resources that could better align with the \nidentified need. . . . [T]he proposed RBP design includes provisions that undercut the notion that fifteen years \nof payments are needed to address the shortfall.”)."},{"page":33,"startToken":10744,"endToken":11033,"text":"33 \nFirst, there is broad consensus among intervenors that the preferred method of \nmeeting the resource adequacy shortfall is through bilateral arrangements between LSEs, \nand/or the end-use customers (i.e., the ratepayers) they serve, and suppliers of new \ncapacity.97  Bilateral arrangements are privately negotiated business deals and, within the \nlimits of the law, parties to such arrangements may freely negotiate the terms.  Parties \nvoluntarily enter into these bilateral arrangements, to which PJM is not a signatory. \nFurthermore, the five Delivery Year minimum is a term required of bilateral arrangements \nthat support Qualifying RBP Offset UCAP MW, not a minimum term required of all \nbilateral arrangements for new capacity.  Thus, the five-year minimum term requirement \ndoes not prohibit parties from entering into bilateral arrangements for new capacity with \nshorter terms.  Those arrangements would not, however, support Qualifying RBP Offset \nUCAP MW. \nSecond, as PJM explained in its July 31 Filing, “a five-year term is not so lengthy \nas to undermine the flexibility needed for commercial contracting or to pose a significant \nbarrier to eligibility for Qualifying RBP Offset UCAP MW . . . .”98  Bilateral arrangements \nremain the preferred approach to meeting the resource adequacy shortfall.  Establishing \nless stringent terms for Qualifying RBP Offset UCAP MW encourages parties to \nvoluntarily enter into bilateral arrangements and, thus, decrement the RBP procurement \ntarget and reduce the quantity of UCAP MW that would otherwise be subject to the more \ninterventionist RBP framework.  Thus, in concluding that the minimum term for bilateral \narrangements supporting Qualifying RBP Offset UCAP MW should be five Delivery \n \n97 See, e.g., DCC Comments at 2; NJ BPU Comments at 2-3; OPSI Comments at 3; Dominion Partial Protest \nand Comments at 4. \n98 July 31 Filing, Transmittal Letter at 39-40."},{"page":34,"startToken":11033,"endToken":11294,"text":"34 \nYears, PJM sought to ensure stability and certainty that new capacity would be developed \nthrough the arrangements without dampening parties’ willingness to enter into bilateral \narrangements. \nThird, as PJM explained in its July 31 Filing, “bilateral agreements may not need \nto be longer than five years to develop new capacity.”99  For a bilateral arrangement, the \nend of a minimum five-year term does not necessarily suggest that the buyers in the \narrangement will no longer be responsible for paying for the new capacity.  Rather, it \nsuggests that, after a minimum five Delivery Year term, parties may seek to transfer or \nrenegotiate the terms of its bilateral arrangements.  This, too, is a feature of the flexibility \nafforded business arrangements, which require little to no intervention from PJM. \nFourth, procurement through the RBP, on the other hand, is a significant, one-time \nintervention in which PJMSettlement would serve as a counterparty that procures RBP \nResources on behalf of LSEs.  In other words, under the RBP, PJM would step in and serve \nas the counterparty that procures supply on behalf of load.   \nFifth, the RBP is only necessary where independent contracting, self-supply, and \nother private arrangements have not proven sufficient to meet the shortfall.  Indeed, where \nparties are unable to procure, or decide not to procure, sufficient capacity for themselves \nby entering into bilateral arrangements, PJM is taking this one-time action by stepping in \nthrough the RBP.  As noted above, bilateral arrangements entered into independently by \ncontracting parties is the preferred and more straightforward pathway to meeting the \ncapacity shortfall. \n \n99 Id. at 40."},{"page":35,"startToken":11294,"endToken":11590,"text":"35 \nSixth, where bilateral arrangements have failed to attract sufficient new capacity to \nmeet new demand, a procurement that offers a fixed term of up to 15 Delivery Years is one \naspect of the RBP intended to attract new supply.  The 15-year term provides price certainty \nthrough the 2042/2043 Delivery Year, in keeping with the NEDC/PJM Governors’ \nPrinciples.100  Furthermore, as the NJ BPU observes, “a price commitment of up to 15 years \nfor qualified new supply resources, will also help attract new supply resources.”101  \nSimilarly, the Ohio FEA notes that procuring “long-term capacity for a fixed term of up to \n15 years” will “incent new resources to address the capacity shortfall.”102  In other words, \nthe 15-year term is intended to motivate supply to participate in meeting the procurement \nshortfall in a timely manner where other measures have failed.   \nThe JCA asserts, “it is also unduly discriminatory to require some ratepayers to pay \nfor fifteen-year procurements when other ratepayers are insulated from RBP charges due \nto exemptions or bilateral/self-supply arrangements of only five years.”103  But ratepayers \ncan choose.  The fact that such a choice gives rise to different results does not amount to \nevidence of undue discrimination. \nTo be clear, the ratepayers at the center of this issue are large loads, which have \npledged to build, bring, or buy their own energy supply and which, for all intents and \npurposes, will be responsible for the costs associated with procuring RBP Resources.  \nThese ratepayers are sophisticated parties that have, by their own terms, “consistently \nmaintained that the most durable solution to PJM’s resource adequacy challenge is to \n \n100 NEDC/PJM Governors’ Principles at 1. \n101 NJ BPU Comments at 3. \n102 Ohio FEA Comments at 5. \n103 JCA Protest at 17."},{"page":36,"startToken":11590,"endToken":11885,"text":"36 \nenable customers adding significant new demand to bring new supply with them.”104  To \nmeet their capacity needs, these ratepayers may enter into bilateral arrangements, which \nare inherently more flexible, including with respect to the length of the term required to \nsupport Qualifying RBP Offset UCAP MW, and which can be used to decrement the \nprocurement target of the zone/area in which that ratepayer is located.  On the other hand, \nthese ratepayers may elect to not act and to thus allow PJM to procure on behalf of the LSE \nthat serves them.  If ratepayers choose the latter, they face payments for RBP Resources \nfor the fixed term of up to 15 Delivery Years.  Each choice presents different results and \nconsequences.  Those differences are not evidence of undue discrimination against \nsimilarly situated ratepayers but rather the outcomes of decisions made by ratepayers who \nhave elected to be situated differently.  \n2. \nThe $555/MW-day (UCAP) cap on the maximum willingness to pay \nin a pay-as-bid procurement is neither too high nor too low.  \nPJM has proposed that the levelized procurement cost of all selected RBP Sell \nOffers not exceed a maximum willingness to pay of $555/MW-day UCAP, on a \nMW-weighted average basis over all Delivery Years of the RBP.105  In other words, under \nthe pay-as-bid structure, some RBP Resources may be paid more, while others may be paid \nless than the proposed $555/MW-day (UCAP) cap. \nAs the Commission order accepting the inputs arising from the latest Periodic \nReview recognizes, PJM is required to submit a Periodic Review of inputs to the RPM, \nincluding Point 1 on the Variable Resource Requirement (“VRR”) curve, which establishes \n \n104 DCC Comments at 2. \n105 July 31 Filing, proposed Tariff, Attachment DD, section 18.5(f)(ii)."},{"page":37,"startToken":11885,"endToken":12170,"text":"37 \nthe price cap, at least every four years.106  For 2028/2029 Delivery Year BRA, the \nuncollared price cap, i.e., Point 1 on the VRR curve, of $555/MW-day (UCAP) was \naccepted by the Commission earlier this year pursuant to the Commission order finding \nPJM’s Periodic Review of certain variables and inputs to the RPM to be just and \nreasonable.107  Neither the Commission nor PJM’s Tariff requires that PJM continuously \nupdate its Periodic Review to reflect changing conditions. \nSome intervenors filed protests and comments asserting that the proposed \n$555/MW-day (UCAP) cap on the maximum willingness to pay is unjust and unreasonable \neither because the cap is too high or too low.  For example, Ohio Consumers’ Counsel \n(“OCC”) argues that $555/MW-day (UCAP) is unjust and unreasonable as it is \n“significantly higher than the clearing price in the 2028/2029 auction of $325/MW-day \nprice cap, which also reflects the scarcity conditions in that auction.”108  JCA likewise \nargues that $555/MW-day (UCAP) is too high, because the “15-year price certainty reduces \nsupplier risk and eases financing . . . the willingness to pay for a 15-year commitment—\nand the price that resources should be willing to accept, if guaranteed for 15 years—should \nbe substantially less than the corresponding amounts for a one-year commitment.”109  The \nIndependent Market Monitor for PJM (“IMM”) asserts that the $555/MW-day cap is a year \n \n106 PJM Interconnection, L.L.C., 194 FERC ¶ 61,049, at P 44 (citing Tariff, Attachment DD, \nsections 5.10(a)(i)-(iii)), order addressing arguments raised on reh’g, 196 FERC ¶ 61,007 (2026). \n107 Id. PP 44-45.  \n108 OCC Protest at 8.  \n109 JCA Protest at 25-28; see IMM Protest at 27-28."},{"page":38,"startToken":12170,"endToken":12499,"text":"38 \nout-of-date, and updating the cap to account for 2026 forwards would result in a lower cap \nof $473/MW-day (UCAP).110 \nOn the other hand, other filed protests and comments argue that the proposed \n$555/MW-day (UCAP) cap on the maximum willingness to pay is too low.  E-Cubed \nPolicy Associates, L.L.C. (“E-Cubed”) protests that the proposed $555/MW-day UCAP \nvolume weighted average price constraint “is not compensatory even under PJM’s \nassumptions” and as a result, “PJM will have trouble attracting capacity to offset any \nportion of the 6,831.3 MW UCAP shortfall.”111  NRG asserts that the RBP should not \nincorporate any cap at all as doing so “necessarily increases the risk that the RBP will clear \nshort, because if the cap binds, PJM will not procure the full RBP target.”112  In the \nalternative, according to NRG, if the Commission is unwilling to accept an RBP with no \ncap, the Commission should accept a soft cap of $866/MW-day, which NRG’s expert \nwitness, John R Morris, asserts to be “a level reflecting a more current estimate of the \nreference [Combustion Turbine’s (“CT”) Cost of New Entry (“CONE”)] and an energy \nand ancillary services offset.”113   \nNotably, no entity that would ultimately be responsible for paying the RBP Charges \n(e.g., DCC, Google, and Amazon) raised concerns with the proposed level of the cap on \nthe maximum willingness to pay set at $555/MW-day (UCAP). \n \n110 IMM Protest at 28 (“If forwards are 24 percent higher, EAS is higher, and point A of the VRR Curve = \nmax[(1.15 x Gross CONE - 0.75 x Net E&AS) or (0.2 x Gross CONE)] is $473/MW-Day UCAP, not \n$555/MW-Day UCAP.” (citing id., Attachment A (Technical Appendix) at 1). \n111 E-Cubed Protest at 2. \n112 NRG Limited Protest at 6 (citing id., Affidavit of John R. Morris on Behalf of NRG Energy, Inc. \n(Attachment A) ¶ 10 (“Morris Aff.”)). \n113 NRG Limited Protest at 10."},{"page":39,"startToken":12499,"endToken":12849,"text":"39 \nMoreover, the fact that some protests and comments argue that the cap is too high, \nwhile others claim it is too low, is not indicative of a flaw in the RBP proposal.  Rather, it \nis an outgrowth of PJM’s concerted effort to strike an appropriate balance and find a \nmiddle-ground that is just and reasonable and not unduly discriminatory or preferential.114  \nIndeed, even intervenors purporting to simply update the revised cap to account for more \ncurrent data propose vastly different figures—from the $473/MW-day cap proposed by the \nIMM, to the $866/MW-day cap calculated by NRG.  Somewhere around the middle sits \nthe $555/MW-day cap proposed by PJM, based on PJM’s latest, Commission-approved \nPeriodic Review. \nAs the July 31 Filing explains, limiting the maximum willingness to pay with a \nprice cap is necessary.  The RBP is not disciplined by direct buy bids that explicitly express \nwillingness to pay and, as Ms. Danielle Croop attests, “it is not reasonable to assume that \nload should be obligated to pay an unlimited amount for supply.  As with other PJM \nprocurement mechanisms, an upper bound helps.”115  Furthermore, as Ms. Croop attests, a \ncap in the context of a procurement in which PJM is not receiving direct buy bids strikes \nan appropriate balance between reliability needs and customer cost protections.116  \nSimultaneously, while imposing a cap, the cap remains flexible, as it is based on a levelized \nMW-weighted average basis over all Delivery Years of the RBP.  Thus, under the proposal, \nsome RBP Resources may be paid more, while others may be paid less.   \n \n114 Furthermore, “[u]nder section 205 of the [Federal Power Act (“FPA”)], the Commission’s inquiry is \nlimited to whether the rates proposed by a utility are just and reasonable, and the Commission need not \ndetermine whether a proposed rate schedule is more or less reasonable than alternative rate designs.”  ISO \nNew Eng. Inc., 173 FERC ¶ 61,204, at P 34 (2020) (citing Cities of Bethany v. FERC, 727 F.2d 1131, 1136 \n(D.C. Cir. 1984)). \n115 July 31 Filing, Croop Aff. ¶ 26. \n116 Id. ¶ 27."},{"page":40,"startToken":12849,"endToken":13122,"text":"40 \nPJM agrees with JCA that a 15-year term creates revenue certainty for supply \nresources and can generally reduce financial and development risk and may improve \nfinancing opportunities through lower capital costs or more favorable financing terms.  \nThus, even if $555/MW-day (UCAP) were lower than the reference CT’s CONE and an \nenergy and ancillary services offset—which, according to the results of the Periodic \nReview, it is not—the 15-year term provides valuable revenue certainty that mitigates \nconcerns that costs have risen since the Periodic Review.  Indeed, it is notable that while a \nhandful of suppliers argued against the proposed level of the cap for the maximum \nwillingness to pay, other suppliers did not raise such concerns.117 \n3. \nPJM has appropriately narrowed the types of capacity resources \nthat are eligible to participate as RBP Resources. \nSeveral comments and protests suggest that the categories of resources that are \neligible to serve as RBP Resources should be expanded, and/or that an asymmetry between \napplicable eligibility requirements for Qualifying RBP Offset UCAP MW and RBP \nResources should be resolved in favor of more inclusive requirements.  The different \nrequirements established for both Qualifying RBP Offset UCAP MW and RBP Resources \nwere thoroughly debated during the CIFP process, are well considered and, for reasons set \nforth in the July 31 Filing,118 have been shown to be just and reasonable.   \nFirst, Constellation Energy Generation, LLC (“Constellation”) suggests that the \nnew Maximum Facility Output requirement should be removed from the requirements to \nqualify as RBP Resources set forth in proposed Tariff, Attachment DD, \n \n117 See generally CPV Comments. \n118 July 31 Filing, Transmittal Letter at 52-54."},{"page":41,"startToken":13122,"endToken":13382,"text":"41 \nsection18.5(b)(i),119 permitting generation resources “[c]omposed of new Installed \nCapacity and new Maximum Facility Output” to qualify as RBP Resources.  Constellation \nopines that the “relevant attribute from a resource adequacy perspective is the new Capacity \nInterconnection Rights.”120  To qualify as RBP Resources, the RBP proposal requires \ngeneration resources to be composed of new Installed Capacity—i.e., new nameplate \ncapacity, new Maximum Facility Output, i.e., the addition of new MW that may be \nphysically injected at a point of interconnection, and new Capacity Interconnection Rights, \ni.e., new deliverable and accredited MW.  These requirements ensure new capacity \nresources that are eligible to serve as RBP Resources meet stringent standards before \nreceiving 15 years of price certainty through the RBP. \nSecond, other intervenors suggest that capacity provided through Surplus \nInterconnection Service (“SIS”) should be eligible to qualify as RBP Resources.  As \ndescribed in the July 31 Filing, PJM recognized that, unlike resources providing Qualifying \nRBP Offset UCAP MW, RBP Resources will have longer-term commitments and price \ncertainty and therefore deliberately proposed comparatively more restrictive criteria for \nRBP Resources.121  Furthermore, as explained in the July 31 Filing and supported by the \naccompanying affidavit of Ms. Croop, PJM expressly walked through the reasoning behind \nexcluding Surplus Interconnection Service, which do not have any independent rights on \nthe PJM system, from qualifying as RBP Resources.122  Notwithstanding the foregoing, \n \n119 Constellation Limited Protest at 2. \n120 Id. at 14. \n121 July 31 Filing, Transmittal Letter at 52. \n122 Id. at 53-54 (citing id., Croop Aff. ¶ 20)."},{"page":42,"startToken":13382,"endToken":13765,"text":"42 \nPJM is actively addressing the alleged barriers to market participation of resources through \nSIS generally through the markets and implementation committee.123 \n4. \nThe proposed gating criteria are appropriately tailored to limit the \nRBP to new capacity resources with a high likelihood of coming \nonline. \nSeveral protests raise concerns that the gating criteria are too stringent and will \nunnecessarily narrow the pool of potential supply that may participate in the RBP.  With \nrespect to gating criteria applicable to Annual DR/DER in particular, some assert that the \ncriteria are so stringent as to be prohibitive,124 while others assert that they are so lax as to \npermit speculative DR/DER to participate in the RBP.125  Others would have the gating \ncriteria effectively expand the role of DR/DER in meeting the capacity shortfall.126 \nFirst, in the July 31 Filing, PJM explained that “PJM will provide sellers the \nopportunity to cure any PJM-identified deficiencies.  Sellers will have five calendar days, \nor up to the close of the bid submission window, to cure.”127  PJM anticipates working \nhand-in-hand with capacity resources, including DR/DER to determine how deficiencies \nmay be cured.   \n \n123 Furthermore, to the extent that Advanced Energy United urges PJM to address barriers to SIS, this is \noutside the scope of this proceeding and PJM notes that it is currently in the middle of working on this issue \nthrough the appropriate stakeholder processes.  See Issue Charge: Hybrid Resources Market Model Selection, \nPJM Interconnection, L.L.C. (Sep. 9, 2026), https://www.pjm.com/-/media/DotCom/committees-\ngroups/committees/mic/2026/20260909/20260909-item-01-2---hybrid-resources-market-model-selection---\nissue--charge---redline.pdf [https://perma.cc/RC5N-2VS5] (endorsed); Issue Charge: Hybrid Resources \nMarket Model Selection, PJM Interconnection, L.L.C. (Aug. 5, 2026), https://www.pjm.com/-\n/media/DotCom/committees-groups/committees/mic/2026/20260805/20260805-item-04-2---hybrid-\nresources-market-model-selection---issue-charge.pdf?_sp=243e40e4-936b-413a-b202-\nfb1b0b43f9c0.1788453807495 [https://perma.cc/B22R-DDFJ]; Market Implementation Committee Draft \nMinutes, PJM Interconnection, L.L.C. (Aug. 5, 2026), https://www.pjm.com/-/media/DotCom/committees-\ngroups/committees/mic/2026/20260909/20260909-draft-minutes---mic---852026.pdf \n[https://perma.cc/5XYH-8ZRG]. \n124 Voltus Comments at 11. \n125 FirstEnergy Comments and Protest at 21. \n126 AEU Comments at 17. \n127 July 31 Filing, Transmittal Letter at 72 (citing id., proposed Tariff, Attachment DD, section 18.5(f)(i))."},{"page":43,"startToken":13765,"endToken":14063,"text":"43 \nSecond, PJM has deliberately tailored the gating criteria applicable to generation \nresources and battery storage, and to DR/DER.  In each case, the gating criteria require that \nthe respective resources provide sufficient evidence to provide PJM with assurances that \nthe resources are highly likely to be fully developed and successful, as opposed to \nspeculative and, in accordance with the purpose of the RBP, come online in relatively short \norder to meet the identified capacity shortfall through the 15-Delivery Year term.   \nVoltus asserts that the requirements on DR/DER “will function as a fence, not a \ngate, with the result that few if any demand-side resources will actually offer, subverting \nPJM’s intention to afford demand-side developers an opportunity to secure long-term price \ncertainty to enable broad and deep new investment in behind-the-meter assets.”128  More \nspecifically, according to Voltus, the requirement on DR/DER to provide “‘[e]xecuted \ncustomer agreements or binding commitments covering the proposed RBP UCAP MW \ncommitment’”129 is overly stringent, particularly as generation/storage resources are not \nrequired to provide evidence of final investments and commitments. \nThe difference in the gating criteria for generation/storage resources and DR/DER \nis by design.  It is the outgrowth of PJM’s recognition that generation/storage resources are \ntied to physical assets.  For such resources, once there is “steel in the ground,” it becomes \ncostly for such assets to exit the market early—i.e., prior to the completion of the \n15-Delivery Year term. \nBy contrast, DR/DER is, by nature, contracts or agreements.  DR/DER contracts \nand agreements are not inherently tied to one dedicated asset.  In addition, there are \n \n128 Voltus Comments at 3. \n129 Voltus Comments at 11 (alteration in original) (quoting July 31 Filing, proposed Tariff, Attachment DD, \nsection 18.5(f)(i)(10))."},{"page":44,"startToken":14063,"endToken":14362,"text":"44 \nnear-zero sunk costs associated with exiting the market or re-entering it, year-to-year.  In \nother words, by design, DR/DER may enter and exit the market year-to-year based on \neconomic and other business decisions.  Indeed, the ability for DR/DER to easily enter and \nexit the market is one reason why, as Advanced Energy United notes, one significant role \nthat DR/DER plays in the RBP proposal is to serve as a “bridge mechanism pending the \navailability of generation or storage capacity not yet in service.”130  On the other hand, in \nrecognition of the fact that DR/DER is, in effect, represented by binding and executed \ncontracts or agreements, the gating criteria need not, contrary to another protestor’s claim, \nprovide evidence of “deployed enabling infrastructure[.]”131 \nFinally, an RBP commitment for DR/DER is ultimately with the Curtailment \nService Provider or DER Aggregator and not tied to one particular physical asset.  RBP is \ndesigned to not allow for replacement of RBP Resources. Only the committed RBP \nResource is eligible for RBP payments. Requiring evidence that the DR/DER locations are \ncontracted for 15 years ensures parity with generation/battery storage resources that \nparticipate in RBP.  The requirement ultimately provides PJM confidence that DR/DER \nserving as RBP Resources will actually be available for the term of the RBP commitment.  \nIn short, PJM’s proposed gating criteria are well considered, balanced, and just and \nreasonable.   \n5. \nPJM is amenable to CPV’s suggested revision to the Site Control \nrequirement set forth in the gating criteria provisions, proposed \nTariff, Attachment DD, section 18.5(f)(i)(2).  \nCPV submitted comments seeking clarification with respect to the gating criteria \nrequiring that Generating Facilities provide evidence of 100% site control.  First, CPV \n \n130 AEU Comments at 16. \n131 FirstEnergy Comments and Protest at 21."},{"page":45,"startToken":14362,"endToken":14675,"text":"45 \nsuggests that, rather than requiring evidence of 100% site control for each Generating \nFacility “for a term of at least three years from the date of submission of the Application,” \nPJM should clarify the proposed Tariff language by instead requiring that the minimum \nthree-year period start from the date of the RBP Sell Offer, i.e., the date of the seller’s \nsubmission of the offer.132  PJM recognizes that the term “Application,” may be ambiguous \nand cause confusion.  Therefore, PJM is amenable to CPV’s suggestion that the three-year \nsite control requirement begin from the date when sellers submit their RBP Sell Offer.  As \ndrafted in the proposed Tariff language, PJM intended the term Application to refer to the \ndate of the RBP Sell Offer.   \nSecond, CPV observes that projects with active interconnection queue positions are \nalready required to meet site control requirements as a prerequisite to continued \nadvancement through the queue.  CPV asserts that imposing an additional site control \nrequirement on projects that are already in the queue could inadvertently exclude resources \nwith a high likelihood of coming to fruition from participating in the RBP “based solely on \nthe discrepancies between the two sets of site control requirements.”133  \nCPV’s request to clarify that the requirement to provide evidence of 100% site \ncontrol for each Generating Facility for a term of at least three years should be applicable \nonly to projects that do not already have an active queue position is reasonable.  Projects \nthat are both already in the interconnection queue and that already meet the relevant \nprerequisites to proceed through the queue will have already demonstrated a high \nlikelihood of actualization and success.  Thus, the existing site control showing required of \n \n132 CPV Comments at 4-5 (quoting July 31 Filing, Transmittal Letter at 73 n.189; id., proposed Tariff, \nAttachment DD, section 18.5(f)(i)(2)). \n133 Id. at 5."},{"page":46,"startToken":14675,"endToken":14989,"text":"46 \ninterconnection customers, combined with the fact that these resources are already in the \nqueue, should suffice. \nIn short, PJM believes CPV suggested redlines to proposed Tariff, Attachment DD, \nsection 18.5(f)(i)(2) is reasonable and could easily make this clarification on compliance \nwithout jeopardizing the commencement of the RBP. \n6. \nPJM requests that the Commission exercise its discretion to correct \na typographical error in proposed Tariff, Attachment DD, section \n18.5(d).  \nUpon review, PJM identified a typographical error in proposed Tariff, \nAttachment DD, section 18.5(d).  As filed, the relevant proposed Tariff provision states: \nTo qualify as a DER Capacity Aggregation Resource that supplies \nRBP UCAP MW eligible to be offered into the Reliability Backstop \nProcurement, a Planned DER Capacity Aggregation Resource must \nmeet \nthe \nrequirements \nof \nTariff, \nAttachment \nDD, \nsections 18.5(b)[.]134 \n \nIt was clearly not PJM’s intent to require DER Capacity Aggregation Resources to \nmeet the requirements in section 18.5(b), which is the provisions for “Generation or Energy \nStorage Resources as an RBP Resource.”  Rather, PJM’s intent was to refer to the general \nrequirements for all resources, in Tariff, Attachment DD, section 18.5(a), “RBP Seller \nEligibility to Participate and General Requirements for Resources Supporting RBP UCAP \nMW.”  PJM therefore respectfully requests that the Commission exercise its discretion135 \nto permit PJM, on compliance, to revise the above, proposed Tariff language to replace the \nreference to “sections 18.5(b)” with “section 18.5(a).”  \n \n134 Proposed Tariff, Attachment DD, section 18.5(d). \n135 Cal. Indep. Sys. Operator Corp., 134 FERC ¶ 61,140 at P 1 (The Commission has exercised its discretion \nto permit changes to tariff language identified by the filing party in an FPA section 205 proceeding “meant \nto clarify . . . existing tariff provisions, eliminate certain inconsistencies, and correct typographical and other \nerrors” subject to a compliance filing implementing such revisions.)."},{"page":47,"startToken":14989,"endToken":15344,"text":"47 \nG. \nThe Requirement for RBP Resources to Offer into the RPM As \nPrice-Takers Is Just and Reasonable. \nConstellation and NRG assert that PJM’s proposal to require RBP Resources to \noffer into the RPM as price-takers is unjust and unreasonable.  According to Constellation \nand NRG, offering RBP Resources into the RPM as price takers will distort RPM Auction \nclearing prices.  Both NRG and Constellation advocate for measures that would effectively \nincrease RPM clearing prices. \n1. \nConstellation and NRG rely on arguments that the Commission has \nconsistently rejected. \nThe Commission has consistently rejected the position that requiring resources that \nare procured outside of a capacity market to offer into the capacity market as price takers \nwould unjustly and unreasonably distort or suppress capacity market clearing prices.136  \nIndeed, as recently as last year, Commission held that offering Reliability Must Run \n(“RMR”) resources into the RPM as price takers “is just and reasonable and consistent with \nCommission precedent[,]” because it: \nreduces the risk that load will procure excess capacity and pay for \ncapacity twice as a result, once through the capacity market and \nagain through an RMR agreement.  In other words, including \nqualifying RMR resources in the capacity market supply stack with \n$0/MW-day offers ensures that these resources clear the market, \nsuch that consumers are protected against excessive capacity \ncosts.137 \nThe Commission expressly stated that it was “not persuaded by protestors’ concerns that \nprice-taker treatment of RMR resources may result in capacity market prices that do not \n \n136 See PJM Interconnection, L.L.C., 190 FERC ¶ 61,088, at P 50 (2025) (rejecting, inter alia, Constellation’s \narguments against offering RMR 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 ¶ 61,204 (2020); N.Y. \nIndep. Sys. Operator, Inc., 150 FERC ¶ 61,116 (2015); N.Y. Indep. Sys. Operator, Inc., 155 FERC ¶ 61,076 \n(2016) (“2016 NYISO RMR Order”); N.Y. Indep. Sys. Operator, Inc., 161 FERC ¶ 61,189 (2017), order on \nreh’g, 163 FERC ¶ 61,047 (2018). \n137 PJM Interconnection, 190 FERC ¶ 61,088 at P 50."},{"page":48,"startToken":15344,"endToken":15737,"text":"48 \nreflect system needs and result in price suppression through the displacement of cost-based \ncapacity offers.”138   \nThe Commission has consistently found that the interest in avoiding \ndouble-payment outweighs the concern of potential price distortion or price suppression.139  \nIntervenors’ protests, including expert testimony attached to those protests, largely mirror \nthose lodged with respect to challenges to RTO/Independent System Operator (“ISO”) \nproposals to treat RMR resources that receive out-of-market payments as price takers in \ncapacity markets.  In its July 31 Filing, PJM explains that requiring the portion of an RBP \nResource that has committed RBP UCAP MW to be offered into the RPM as a price taker \nis necessary where RBP Resources are already being paid for by the responsible LSEs.  \nPlacing a must-offer requirement on RBP Resources and requiring such offers to be \nsubmitted as price takers during the term of such commitment ensures that load does not \ndouble pay for capacity.140   \nIn its protest, Constellation argues that requiring RBP Resources to offer as price-\ntakers will distort the RPM price signal, and may “increase[] retirement risk, incent[] \nresources to export to other markets, and delay[] market entry and capital investment—\n \n138 Id. \n139 See, e.g., PJM Interconnection, L.L.C., 137 FERC ¶ 61,145, at P 208 (2011) (accepting PJM’s proposed \napproach to self-supply resources in capacity auction finding that “it appropriately balances the need to \nprotect against uneconomic entry while also mitigating parties’ concerns about having to pay twice for \ncapacity as a result of failing 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 entry through \ngreater investor assurance and protect consumers from very high year-one prices.” (citing New Eng. Power \nGenerators Ass’n v. FERC, 881 F.3d 202, 209 (D.C. Cir. 2018))); see also ISO New Eng. Inc., 155 FERC \n¶ 61,023, at P 68 (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 suppression,” the \nexemption was just and reasonable because ISO NE “took steps to limit the amount of price suppression” \nand enabled the continued procurement of “sufficient capacity to meet reliability targets”). \n140 July 31 Filing, Transmittal Letter at 57."},{"page":49,"startToken":15737,"endToken":16046,"text":"49 \nleaving PJM short yet again when delayed load arrives.”141  NRG’s protest similarly asserts \nthat requiring RBP Resources to offer into the RPM as price takers, particularly after \ninterventions that “produced ‘unsustainably low price levels for three delivery years’” cuts \nagainst the need to prevent capacity prices from “‘crash[ing] to levels that make new \ninvestments likely unprofitable over the life of the assets.’”142 Constellation and NRG’s \npositions in the above-captioned docket effectively recycle arguments previously made \nwith respect to RMR resources that have been consistently and summarily dispatched by \nthe Commission. \nConstellation and NRG’s efforts to support their price distortion or suppression \narguments are likewise unavailing.  Constellation offers expert testimony in support of the \ntheory that requiring RBP Resources to offer into the RPM as price takers can distort RPM \nprice signals, giving rise to a parade of horribles, particularly when “[a]vailable RBP \nUCAP precedes or exceeds the RBP-Related Load reflected in an RPM Auction.”143  \nSimilarly NRG relies on expert testimony to argue that requiring “resources with RBP \ncommitments [to] offer as price-takers into RPM Auctions for the associated Delivery \nYears ‘is antithetical to creating a normal capacity market.’”144 \nAs a threshold matter, it is unlikely that a significant portion of the RBP related \nload does not materialize in the same RPM Auction that the committed RBP Resources \nwould be offered as price-takers.  Nonetheless, should that occur and a large portion of \nRBP related load somehow does not materialize and is not reflected in the demand curve, \n \n141 Constellation Limited Protest at 4 (footnotes omitted). \n142 NRG Limited Protest at 10 (quoting id., Morris Aff. ¶¶ 29, 31). \n143 Constellation Limited Protest at 4 & n.15 (citing Affidavit of Roy J. Shanker, Ph.D., in Support of \nConstellation (Appendix A) ¶¶ 13-16 (“Shanker Aff.”)). \n144 NRG Limited Protest at 10 (quoting id., Morris Aff. ¶ 25)."},{"page":50,"startToken":16046,"endToken":16404,"text":"50 \nit would still be appropriate to include the RBP Resources in the supply curve for the RPM \nAuction as price-takers.  The actual quantity of available supply should be reflected in the \nRPM Auctions.  Excluding available supply, consisting of RBP Resources that loads have \nseparately paid for, from the capacity auctions would artificially inflate RPM clearing \nprices and send incorrect market signals to retain excess capacity that may no longer be \nnecessary in the unlikely event the RBP related load does not materialize.  In addition, RBP \nResources are being paid for by LSEs that are responsible for RBP Charges and should not \nbe double charged.  Absent requiring RBP Resources to be price-takers in the RPM \nAuctions, the loads that pay for such RBP Resources could be double charged for capacity \neven under the contract for differences approach because if such resources do not clear the \nRPM Auction, there would be no capacity revenues to offset the RBP Charges. \nMoreover, in the context of RMR resources, the Commission has consistently not \nbeen swayed by expert testimony submitted by proponents of the price \ndistortion/suppression theory.  As the Commission has held, such testimony has failed to \nestablish that “significant capacity price decreases have occurred in the rest-of-state spot \nmarket actions, solely as a consequence of the [RMR resources].”145  Indeed, the \nCommission has even held that even if, arguendo, evidence of price suppression did \ndemonstrate that the participation of RMR resources receiving must-offer price taker \ntreatment suppresses capacity auction clearing prices, that evidence fails to demonstrate \nthat the reduction to price is unjust and unreasonable.  The Commission has, in such cases, \nrelied on RTOs/ISOs to strike the appropriate balance.146  Furthermore, the Commission \n \n145 Indep. Power Producers of N.Y., Inc. v. N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,214, at P 67 \n(2015) (“IPPNY”), order on reh’g & clarification, 170 FERC ¶ 61,118 (2020). \n146 See, e.g., ISO New Eng., 173 FERC ¶ 61,198 at P 74; see also ISO New Eng., 155 FERC ¶ 61,023 at P 68 \n(finding that, where ISO-NE sought to “balance both the harms and the benefits to customers from an"},{"page":51,"startToken":16404,"endToken":16765,"text":"51 \nhas constantly held that “the price taker design accurately reflects” retained resources’ “low \ngoing-forward costs.”147  Price-taker offers are consistent with the expected outcome of \ncompetitive markets because the out-of-market revenue (e.g., cost-of-service RMR \nagreements and RBP Charges) must be accounted for.148  \nAt bottom, neither Constellation nor NRG provides any reason to depart from well-\nestablished Commission precedent, which has consistently found in favor of RTO/ISO \nproposals that require out-of-market resources to be treated as price takers in capacity \nmarkets, even over the protests of intervenors lodging arguments similar to those raised by \nConstellation and NRG here. \n2. \nNRG’s assertion that RBP Resources offering into the RPM should \nbe subject to an offer floor of $175/MW-day (UCAP) is without \nsupport and an impermissible attempt to expand the focused \nMinimum Offer Price Rule. \nNRG proposes that imposing an offer floor on RBP Resources will guard against \nthe risk that offering RBP Resources as price takers will “depress prices in the RPM \nAuctions” and “undermine the viability of PJM’s capacity market.”149  According to NRG, \n“an offer floor of $175/MW-day (UCAP) apply to offers from resources with RBP \n \nexemption that might result in some price suppression,” the exemption was just and reasonable because ISO \nNE “took steps to limit the amount of price suppression” and enabled the continued procurement of \n“sufficient capacity to meet reliability targets”); PJM Interconnection, 137 FERC ¶ 61,145 at P 209 \n(accepting PJM’s proposed approach to self-supply resources in capacity auction finding that “it \nappropriately balances the need to protect against uneconomic entry while also mitigating parties’ concerns \nabout having to pay twice for capacity as a result of failing to clear in RPM”); ISO New Eng. Inc., 179 FERC \n¶ 61,139, at P 45 (2022) (finding that ISO-NE had “met its burden to show that the proposed revisions \nappropriately balance the need to mitigate the potential exercise of buyer-side market power against the harms \nof over-mitigation”). \n147 See supra note 144; see IPPNY, 150 FERC ¶ 61,214 at P 66; 2016 NYISO RMR Order, 155 FERC \n¶ 61,076 at P 83. \n148 See supra note 145. \n149 NRG Limited Protest at 12."},{"page":52,"startToken":16765,"endToken":17083,"text":"52 \ncommitments equal to the forecasted load does not materialize.”150  NRG furthermore \nclaim that the $175/MW-day (UCAP) is appropriate, as it is one-half of the administrative, \ntime-limited price collar that is currently in place.   \nNRG’s arguments are unavailing.  First, as that price collar has been extended \nthrough the 2029/2030 Delivery Year, the $175/MW-day (UCAP) price floor will apply to \nRBP Resources as well as all other resources offering into the RPM through the 2029/2030 \nDelivery Year.   \nSecond, in the Delivery Years after the price collar is lifted, NRG’s proposed \n$175/MW-day (UCAP) price floor would effectively expand PJM’s targeted Minimum \nOffer Price Rule (“MOPR”).  There is no reason to do so.  In 2023, the United States Court \nof Appeals for the Third Circuit upheld PJM’s targeted MOPR on grounds that the \nCommission had identified sufficient reasons for departing from a more expanded MOPR, \nincluding that an expanded MOPR permitted “artificially inflated price [that] will falsely \nsignal that new entry is needed or that existing resources should forestall retirement, with \npotentially detrimental effects on PJM’s energy and ancillary service markets.”151 \nNRG’s proposal effectively cuts against the Commission’s decision to accept \n“narrowly tailored” MOPRs over more expanded MOPRs.152 As the Commission observed \nin ruling on ISO-NE MOPR reforms, “ISO-NE’s limited renewables exemption [to the \nMOPR rule] reflects the balancing of not paying twice for capacity with the alternative \n \n150 Id. at 12. \n151 PJM Power Providers Grp. v. FERC, 88 F.4th 250, 272 (3d Cir. 2023) (internal quotation marks omitted). \n152 ISO New Eng., 155 FERC ¶ 61,023 at P 36; see also ISO New Eng. Inc., 158 FERC ¶ 61,138 at P 43 (“The \nCommission, in balancing generators’ and customers’ interests, reasonably recognized how these \ndevelopments, over time, have tipped the scales, and accepted a narrowly tailored exemption to reduce the \nlikelihood that customers will have to pay for redundant capacity.”)."},{"page":53,"startToken":17083,"endToken":17376,"text":"53 \ninterest in reducing the potential for price suppression.”153  In fact, the Commission found \nthat the ISO-NE MOPR reforms were just and reasonable, notwithstanding any price \nsuppressive effects.  The Commission held that the expanded application of the MOPR had \nprecluded certain resources from receiving a capacity obligation, which, in turn, sent price \nsignals that did not reflect the actual resource mix and interfered with efficient markets, \nultimately pushing market prices up.154  In other words, in response to arguments that the \nexpanded MOPR had been necessary to keep prices from reflecting inaccurately low prices \nand resource scarcity, the Commission held that narrowing the MOPR was necessary to \nprevent inaccurately high prices and potential resource oversupply. \nThird, PJM’s targeted MOPR is focused, in part, on protecting against the exercise \nof buyer-side market power.  NRG has not demonstrated the potential for the exercise of \nbuyer-side market power in the RBP.  The RBP is a pay-as-bid procurement, not a single \nclearing-price auction.  In a pay-as-bid auction, sellers of new capacity participating in the \nRBP simply do not have the incentive or ability to suppress or even affect clearing prices \nto benefit their portfolio of load.  The RBP is not a construct that risks enabling buyers to \nexercise market power.   \nFourth, a floor price for RBP Resources set at $175/MW-day is unsupported.  The \nexisting MOPR rules provide default CONE and Avoidable Cost Rates for each resource \nclass.  It would be inappropriate to establish a uniform floor price for all RBP Resources \nbased on the existing floor price used in the price collar that is set to expire after the RPM \nAuctions associated with the 2029/2030 Delivery Year. \n \n153 ISO New Eng. Inc., 173 FERC ¶ 61,161, at P 112 (2020).   \n154 Id. P 52."},{"page":54,"startToken":17376,"endToken":17718,"text":"54 \n3. \nIt is unnecessary to exclude RBP demand and RBP supply from the \nRPM for purposes of price formation. \nConstellation suggests that “removing the separately procured RBP supply and the \ncorresponding RBP-related demand from RPM price formation . . . eliminates the threat of \nany double payment and removes the deleterious impact on RPM.”155  PJM has never \nrequired that price formation in the RPM turn on perfectly matched demand and supply.  \nIndeed, in 2024 PJM proposed, and in 2025, the Commission subsequently accepted, an \nextension of the capacity must-offer requirement to all available Existing Generation \nCapacity Resources.156  \nThe Commission has approved resource-specific exceptions and categorical \nexemptions to the must-offer requirement in narrow circumstances, when “reasonable and \nsufficiently narrow to prevent withholding.”157  Constellation does not argue that an \nexception to the must-offer requirement for RBP Resources is necessary to prevent \nwithholding.  Rather, the crux of Constellation’s argument is simply that a mismatch \nbetween available RBP UCAP and the timely addition of RBP-related load risks may \nimpact price formation and create reliability risks.  But that observation is not dispositive.  \nIndeed, similar dynamics exist today in the RPM.  For example, integrated utilities that \nhave built more than needed today based on forecasted load growth, such excess supply \nwould not be excused from the must offer requirement in the RPM.  As PJM’s IMM, Dr. \n \n155 Constellation Limited Protest at 10-11 (citing id., Shanker Aff. ¶¶ 25-30). \n156 PJM Interconnection, L.L.C., Extending the Capacity Must-Offer Requirement to All Generation Capacity \nResources of PJM Interconnection, L.L.C., Docket No. ER25-785-000 (Dec. 20, 2024); PJM \nInterconnection, L.L.C., 190 FERC ¶ 61,117, order addressing arguments raised on reh’g, 191 FERC \n¶ 61,221 (2025).  \n157 PJM Interconnection, L.L.C., 151 FERC ¶ 61,208 at P 355, order denying request for clarification, \ngranting in part request for reh’g, granting in part complaint, & directing compliance filing, 152 FERC \n¶ 61,064 (2015), order on reh’g & compliance, 155 FERC ¶ 61,157 (2016), aff’d sub nom. Advanced Energy \nMgmt. All. v. FERC, 860 F.3d 656 (D.C. Cir. 2017)."},{"page":55,"startToken":17718,"endToken":18154,"text":"55 \nJoseph E. Bowring observed in testimony before the Pennsylvania House of \nRepresentatives, Environmental Resources and Energy Committee in 2024, “[t]he purpose \nof the RPM must offer rule, which has been in place since the beginning of the capacity \nmarket in 1999, is to ensure that the capacity market works based on the inclusion of all \ndemand and all supply, and to prevent the exercise of market power via withholding of \nsupply.”158 \nH. \nArguments That RBP Should Be Extended to FRR Entities Are Baseless. \nEast Kentucky Power Cooperative, Inc. (“EKPC”) argues that, because the scope \nof PJM’s proposal does not extend to FRR Entities, the proposal “creates comparability \nconcerns and unduly discriminates against RPM Capacity Market LSEs.”159  This \nargument is baseless.  As discussed throughout the July 31 Filing and this Answer, the \nscope of RBP is to procure capacity to meet the resource adequacy needs of new large loads \nthat did not bring their own capacity.  This does not implicate FRR Entities.160  By \ndefinition, FRR Entities must bring new capacity for all new loads within their territory.161  \nIf an FRR Entity does not include sufficient capacity in its FRR Capacity Plan, the FRR \nEntity is subject to “an FRR Commitment Insufficiency Charge, in an amount equal to two \n \n158 Testimony of Joseph E. Bowring, the Independent Market Monitor for PJM, Pennsylvania House of \nRepresentatives, Environmental Resources and Energy Committee, Pennsylvania General Assembly, 5 \n(Oct. 16, \n2024), \nhttps://www.palegis.us/house/committees/meeting-archive?MeetingId=4180 \n[https://perma.cc/A5XT-SV5W]. \n159 EKPC Protest at 45. \n160 In the July 31 Filing, PJM inadvertently submitted a revision to RAA, Schedule 8.1D, section 1.1:  “An \nFRR Entity may not use an Existing Generation Capacity Resource not owned by such FRR Entity as of \nJune 1, 2027 or any resource committed through the Reliability Backstop Procurement to satisfy its Capacity \nFRR Plan.”  PJM did not intend to include this revision as part of the RBP proposal, and did not discuss or \nin any way support this change in the transmittal letter.  Rather, PJM intended to (and did) submit a revision \nin this vein as part of its IRAS proposal in Docket No. ER26-3515-000.  Consistent with PJM’s existing \nconsent to the Commission making modifications to the July 31 Filing, PJM requests that the Commission \nreject this specific revision to RAA, Schedule 8.1D, section 1.1 and not accept this revised eTariff record.  \n161 See RAA, Article 1 (defining FRR Service Area states that “the FRR Entity has or assumes the obligation \nto provide capacity for all load (including load growth) within such area.”)."},{"page":56,"startToken":18154,"endToken":18445,"text":"56 \ntimes the Cost of New Entry for the relevant location” multiplied by the MW of capacity \nshort.162  In contrast, LSEs participating in RPM have no requirement to bring capacity \nsufficient to meet their needs.  Indeed, that is exactly what RBP is designed to do—bring \nnew capacity for the new large loads that did not bring their own.  Thus, contrary to EKPC’s \nclaim,163 LSEs participating in RPM are not similarly situated to FRR Entities.   \nI. \nPJM’s Proposed Cost Allocation Approach Appropriately Assigns Cost \nResponsibility to the Electric Distributor Zone/Areas That Submitted the \nLoad Adjustments Driving the Need for the RBP. \nSeveral parties filed comments regarding PJM’s proposed cost allocation approach.  \nAs discussed below, representatives for state regulatory bodies generally support PJM’s \napproach, while some of those that would be allocated cost responsibility object.   \n1. \nState regulatory bodies, the DCC, and AMP support PJM’s cost \nallocation approach. \nAs noted, PJM’s proposal received broad state support—which is significant, as \nstate action is necessary to ensure those LSEs serving the data centers and other large loads \ncausing the need for the procurement of RBP Resources bear the costs.  OPSI stated \nagreement that “successful implementation of the RBP will require timely retail regulatory \naction that ensures existing retail loads are insulated from or share in the cost of the RBP \nonly to the extent consistent with state retail ratemaking approvals.”164  OPSI continued \nthat the states’ retail regulators have jurisdiction “to allocate[e] RBP costs to retail \ncustomers” and that “several states have already begun implementing or considering retail \nratemaking reforms designed to more closely align the costs associated with new large-\n \n162 Id., Schedule 8.1D, section 7. \n163 See EKPC Protest at 46. \n164 OPSI Comments at 2."},{"page":57,"startToken":18445,"endToken":18704,"text":"57 \nload development with those customers.”165  The NJ BPU stated that it “will work closely \nwith other state entities and utilities to ensure that these [RBP] costs are properly allocated \nto incoming data centers.”166  The Ohio FEA stated that, “[w]hile the allocation of any \nwholesale costs to retail customers is within the purview of each state, . . . it is widely \nagreed that the costs of the RBP should be paid by the data centers seeking new capacity \nduring this time of regional demand/supply constraint.”167  Therefore, “successful \nimplementation of the RBP means that, upon Commission approval, states and utilities \nmust work expeditiously to align state regulations and cost-allocation frameworks (i.e., \ntariffs) with the RBP structure, as needed, to ensure that the cost of procuring long-term \ncapacity under the RBP is appropriately assigned to the cost causers,” i.e., data centers and \nother large loads driving the Load Adjustments.168  Indeed, after PJM submitted this RBP \nproposal, Josh Shapiro issued an executive order to protect Pennsylvania consumers by \n“charg[ing] the appropriate data center customers for any PJM reliability backstop auction \ncosts . . . .”169 \nPJM’s cost allocation proposal also received support from load interests.  American \nMunicipal Power, Inc. (“AMP”) supports PJM’s approach to allocate RBP costs “to those \nElectric Distributor zone/areas that have provided to PJM projections of large load growth \n \n165Id. \n166 NJ BPU Comments at 4. \n167 Ohio FEA Comments at 5. \n168 Id. at 6. \n169 Pa. Exec. Order No. 2026-05, 56 Pa. B. 5902 § 7.1084 ¶ 2(b)(1) (Aug. 18, 2026)."},{"page":58,"startToken":18704,"endToken":19017,"text":"58 \nbetween 2026 and 2028.”170  AMP agrees that PJM’s “allocation framework is consistent \nwith cost causation principles and the Ratepayer Protection Pledge.”171 \nIn addition, the DCC stated that “[t]he costs associated with serving new large loads \nshould be borne by new large loads contributing to resource inadequacy and should not be \nshifted to existing residential, commercial, or industrial customers or new large loads that \nhave not contributed to resource inadequacy.”172  The DCC also stated that “[s]ignificant \nwork will be required at the state level to translate PJM’s wholesale allocation into retail \ntariffs that accurately assign RBP costs to the large loads responsible for the incremental \ndemand, while protecting other customers from inappropriate cost shifts.”173   \nRetail Energy Supply Association (“RESA”) likewise notes that “[i]f the RBP \nProposal is accepted substantially as filed, every PJM state—and particularly those open \nto retail competition—will need to move immediately to identify Large Load Customers \nand to assign RBP costs and collateral obligations to those customers and their LSEs.  \nRESA intends to participate in those proceedings . . . .”174 \nPJM stands ready to assist the states in their efforts to allocate RBP costs to those \nLSEs serving the loads driving the need for the RBP.  Therein fact, PJM and the PJM states \nhave been engaging in collaborative efforts to work towards addressing questions raised \n \n170 AMP Comments at 3 & n.6 (citing July 31 Filing, Croop Aff. ¶¶ 41-43; id., Transmittal Letter at 96-97, \n101).   \n171 Id. at 3 & n.7 (citing July 31 Filing, Transmittal Letter at 100-08).  In response to AMP’s request, PJM \nclarifies that “Electric Distributor zone/area” used in the proposed RBP Tariff rules holds the same meaning \nas accepted by the Commission in Docket No. ER24-2447.  See July 31 Filing, Transmittal Letter at 100-01. \n172 DCC Comments at 4. \n173 Id. at 5. \n174 RESA Protest at 7."},{"page":59,"startToken":19017,"endToken":19295,"text":"59 \nby intervenors about implementation, including cost allocation under the cooperative \nfederalism framework.175   \n2. \nLSEs serving new large loads that would be allocated cost \nresponsibility present several meritless arguments opposing cost \nresponsibility for their new large loads’ contribution to the current \nshortfall. \nPJM’s cost allocation proposal is opposed by those who would be responsible for \nbearing the costs of RBP Resources—data center developers and entities that are \ncontracting to serve new large loads.  Specifically, it is opposed by Amazon, Dominion, \nNOVEC, FirstEnergy Service Company (“FirstEnergy”), AEP, and EKPC.  Each of these \nentities (or their parent) is a signatory to the Ratepayer Protection Pledge176 and, as such, \ncommitted to “build, bring, or buy the new generation resources and electricity needed to \nsatisfy their new energy demands, paying the full cost of those resources whether by \nbuilding, or buying from, new or otherwise additive power plants.”177  The RBP is a \nmechanism to bring and buy new generation resources and electricity to meet the demands \nof new large loads.  As discussed below, these parties’ objections to PJM’s cost allocation \napproach are meritless. \n \n175 To the extent that some intervenors have requested that additional or enhanced information sharing with \nstate entities and affected loads, PJM notes that it will adhere to existing information sharing and \nconfidentiality provisions.  \n176 \nData \ncenters \npay \ntheir \nway. \nRatepayers \npay \ntheirs., \nThe \nWhite \nHouse, \nhttps://www.whitehouse.gov/ratepayer-protection-pledge/ [https://perma.cc/3WBQ-RXW4] (last visited on \nSep. 8, 2026) (“White House Ratepayer Protection Pledge Signatories”) (listing all 317 signatories). \n177 \nRatepayer \nProtection \nPledge, \nThe \nWhite \nHouse \n(Mar. \n4, \n2026), \nhttps://www.whitehouse.gov/releases/2026/03/ ratepayer-protection-pledge/ [https://perma.cc/N8PH-K82T] \n(“Ratepayer Protection Pledge”)."},{"page":60,"startToken":19295,"endToken":19866,"text":"60 \na. \nThe procurement target is appropriately based on a snapshot \nof the RTO-wide shortfall observed in the 2028/2029 BRA. \nAEP and Amazon claim that allocating RBP cost responsibility based on current \ncost causation over the 15-year term of the RBP commitment is unjust and unreasonable.178  \nThe Commission can easily dismiss this argument.  As an initial matter, this is not a claim \nthat the new large loads did not cause the need for the capacity procured through the RBP, \nbut rather an argument over whether they should have to pay for the capacity for the entire \ncapacity commitment term.179  In this context, the answer is yes.   \nThe Commission has long held that relying on snapshots is an acceptable and \nappropriate method for establishing baselines or targets,180 and the objections raised herein \nhave provided no reason for the Commission to depart from that precedent—particularly \nwhere PJM has proposed a conservative figure based on an RTO-wide procurement target, \n \n178 See AEP Limited Protest at 29-30. \n179 AEP’s other argument against allocating costs based on the Load Adjustments driving the shortfall is more \ntenuous.  AEP appears to argue that because the proposed RBP is not procuring RBP Resources on a \nlocational basis, allocating the costs to the Electric Distributor zone/area with Load Adjustments is unjust \nand unreasonable.  AEP Limited Protest at 29.  This argument ignores that the RBP is designed to address \nthe regional shortfall driven by these large loads, not the need for locational capacity driven by transmission \nconstraints.  As the Commission well understands, all capacity in PJM is deliverable to all loads in PJM until \ntransmission constraints are met.   \n180 See, e.g., Joint Consumer Representatives v. PJM Interconnection, L.L.C., 153 FERC ¶ 61,187, at P 32 \n(2015) (denying complaint and reasoning that “[w]hile there will inevitably be some difference between \nPJM’s load forecast and the amount of capacity that PJM ultimately needs in a given Delivery Year, the \nrecord indicates that PJM has taken steps to ensure the reasonableness of the 2015 Load Forecast, including \nmaking a statistical adjustment, based on a percentage of error it had seen in the load forecast over recent \nyears, to account for the effects of energy efficiency programs.” (citation omitted)); see also PJM \nInterconnection, L.L.C., 162 FERC ¶ 61,136, at P 24 (2018) (rejecting Dominion’s proposal to revise PJM’s \nTariff “to incorporate an average demand feature into how it determines a transmission customer’s \ncontribution to Network Service Peak Load.  Dominion argues that such a feature is necessary because, \nwithout it a single transmission customer could shift costs to other customers since the billing determinants \nare otherwise calculated using a single-hour snapshot of customer demand each year.”); Del. Pub. Serv. \nComm’n v. PJM Interconnection, L.L.C., 166 FERC ¶ 61,161, at P 46 (2019) (finding that “based on the \nrecord developed here regarding the stability-related reliability issue category, we do not find the limitations \nof a snapshot analysis to be sufficiently problematic to alter our conclusion that the Stability Deviation \nMethod is just and reasonable”); BP W. Coast Prods., LLC v. SFPP, L.P., 121 FERC ¶ 61,141, at P 6 (2007) \n(noting that the “screening approach at the suspension phase is a snap shot approach that avoids extensive \narguments over issues of accounting accuracy and rate reasonableness within the time limits available for \nCommission review, and highlights the simplicity of the filing procedure”)."},{"page":61,"startToken":19866,"endToken":20195,"text":"61 \nintended as an initial step that will kick-start PJM’s efforts to procure sufficient to capacity \nto support the needs of the region. \nThe PJM Region is experiencing a capacity shortfall that can be directly attributed \nto the Load Adjustments submitted to PJM by entities in the Electric Distributor zone/areas \nthat would be allocated RBP cost responsibility—and AEP and Amazon do not allege \notherwise.  Rather, they state the unremarkable fact that load growth patterns change over \ntime.181  The RBP is a one-time procurement of new capacity resources to address the \nresource adequacy needs of the Load Adjustments submitted for the Electric Distributor \nzone/areas.  This squarely meets the requirement that “costs must be allocated consistent \nwith cost causation principles.”182 \nMoreover, establishing the procurement target based on a snapshot of the \nRTO-wide shortfall for the term of the RBP commitment 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 of \nsuch commitment.  This would allow LSEs to make long-term plans for such RBP Charges, \nincluding arrangements to post collateral, and avoid scenarios where new load bilaterally \ncontracts for new capacity but subsequently gets allocated RBP Charges. \nb. \nPJM’s proposed cost allocation approach appropriately \nassigns RBP Charges to the zones/areas with reported new \nload that is not matched with new capacity. \nNOVEC argues that “PJM has not adequately demonstrated why the incremental \ncosts and substantial credit obligations associated with RBP Resources should be \n \n181 See AEP Limited Protest at 29; Amazon Comments at 4-5. \n182 Entergy Servs., LLC, 196 FERC ¶ 61,166, at P 25 (2026) (citing N. States Power Co., 64 FERC ¶ 61,324, \nat 63,379 (1993) (“[T]he fundamental principle of cost causation [is] that costs should be recovered in the \nrates of those customers who utilize the facilities and thus cause the cost to be incurred.”))."},{"page":62,"startToken":20195,"endToken":20530,"text":"62 \nconcentrated on designated RBP buyers without accounting for material capacity-market \nbenefits those resources may provide to other PJM load.”183  The Commission should reject \nthis argument.  NOVEC seeks to establish a false standard for cost allocation approaches.   \nAs the Commission is well aware, the cost causation principle requires that costs \nbe allocated “at least roughly commensurate” with the benefits.184  This means that “all \napproved rates reflect to some degree the costs actually caused by the customer who must \npay them.”185  To the extent an entity causes the costs to be incurred, it will have to pay its \nshare.  Importantly, consistent with the “roughly commensurate” principle, “nothing \nrequires the Commission to ensure full or perfect cost causation,”186 and the Commission \n“is not bound to reject any rate mechanism that tracks the cost causation principle less than \nperfectly.”187   \nPJM’s proposed approach easily meets this standard.  As PJM explained in the \nJuly 31 Filing, “PJM has tracked Load Adjustments in zones/areas to the level of \ngranularity that is feasible,”188 “based on equations that ‘allow PJM to allocate a capacity \nobligation associated with a load adjustment to the zone/area in which the adjustment \noccurs.’”189  PJM’s approach relies on the best information available and properly allocates \ncosts to those Electric Distributor zone/areas with Load Adjustments (that were requested \nby the Electric Distributor or LSE).  The result is a cost allocation methodology that assigns \n \n183 NOVEC Protest at 16. \n184 Ill. Com. Comm’n v. FERC, 576 F.3d 470, 477 (7th Cir. 2009).   \n185 KN Energy Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992). \n186 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 88 (D.C. Cir. 2014).    \n187 Sithe/Indep. Power Partners, L.P. v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002) (citation omitted).  \n188 July 31 Filing, Transmittal Letter at 103. \n189 Id. at 102 (quoting PJM Interconnection, L.L.C., 188 FERC ¶ 61,200, at P 37 (2024))."},{"page":63,"startToken":20530,"endToken":20946,"text":"63 \ncost responsibility to the zones/areas with reported new load that is not matched with new \ncapacity—i.e., the zones/areas and LSEs can be said to have caused the target resource \nadequacy shortfall.   \nHowever, to be clear, PJM has taken its approach as granular as it can go.  PJM is \nallocating costs to specific zones, but the allocation to large loads within an Electric \nDistributor’s zone/area is a matter of retail allocation for the states, consistent with the \nNEDC/PJM Governors’ Principles.190  As the DCC stated, “[u]ltimately, the RBP’s cost-\nallocation framework should accomplish a straightforward objective: large loads should \npay the costs associated with serving their incremental demand, receive appropriate credit \nwhen they bring new capacity to meet that demand, and existing customers should not be \nleft with the bill.”191 \nIn any event, while there could be alternative cost allocation approaches, that may \nalso be just and reasonable, that does not mean PJM’s proposal is not just and reasonable.192   \nc. \nTo be just and reasonable, PJM’s cost allocation approach \ndoes not need to allocate costs to data centers specifically. \nFirstEnergy contends that “PJM’s cost allocation proposal is not meaningfully \ntargeted to ensure the customers ultimately allocated the costs of the RBP will be entities \n \n190 The governors of the 13 states in the PJM Region committed to “[u]se all available authorities to ensure \nthat their state public utility commissions design rate class structures to ensure that their states' LSEs allocate \ntheir share of the cost to procure new capacity through the Reliability Backstop Auctions to new data center \nloads that have not otherwise procured capacity or agreed to be curtailable.”  NEDC/PJM Governors’ \nPrinciples at 2. \n191 DCC Comments at 6. \n192 See, e.g., Cities of Bethany, 727 F.2d at 1131 (“FERC has interpreted its authority to review rates under \n[the FPA] as limited to an inquiry into whether the rates proposed by a utility are reasonable—and not to \nextend to determining whether a proposed rate schedule is more or less reasonable than alternative rate \ndesigns.” (citing Pub. Serv. Co. of Ind., 56 FPC 3003 (1976)); Midwest Indep. Transmission Sys. Operator, \nInc., 127 FERC ¶ 61,109, at P 20 (2009) (“It is well established that there can be more than one just and \nreasonable rate . . . .” (citing Am. Elec. Power Serv. Corp. v. Midwest Indep. Transmission Sys. Operator, \nInc., 122 FERC ¶ 61,083, at P 88, order on reh’g, 125 FERC ¶ 61,342 (2008)))."},{"page":64,"startToken":20946,"endToken":21273,"text":"64 \ncausing the need for the procurement of new generation—i.e. new data center customers, \nin accordance with the [NEDC/PJM Governors’ Principles].”193  The basis for this \ncontention is that PJM did not identify specific data centers but instead is relying on the \nElectric Distributor / LSE submitted Load Adjustments, and that such Load Adjustments \n“are not limited to new data centers.”194  It is fallacious to suggest that a just and reasonable \ncost allocation approach must either identify specific loads (which are not \nFPA-jurisdictional actors) and not the LSEs serving those loads or be limited to one type \nof load when the resource adequacy shortfall is caused by all types of loads that comprise \nthe subject Load Adjustments.  Further, as PJM explained in the July 31 Filing,195 the \nconcept of Load Adjustments was added in 2024 “to better allocate, to zones/areas, \nlocalized load adjustments used to determine capacity obligations for [LSE]”196 and were, \nas PJM noted at the time, “spurred by the recent proliferation of data centers that are \ncontributing to large additions of forecasted load concentrated within a specific wholesale \nmetering area.”197  The Load Adjustments allow for “more accurate[] assign[ment of] \ncapacity obligations to LSEs.”198  Finally, in the NEDC/PJM Governors’ Principles, the \ngovernors of PJM states committed to “to ensure that their states’ LSEs allocate their share \nof the cost to procure new capacity through the [RBP] to new data center loads that have \nnot otherwise procured capacity or agreed to be curtailable.”199  Thus, it is appropriate for \n \n193 FirstEnergy Comments and Protest at 12.  \n194Id. \n195 See July 31 Filing, Transmittal Letter at 100-01. \n196 PJM Interconnection, 188 FERC ¶ 61,200 at P 1. \n197 PJM Interconnection, L.L.C., Proposal to Better Account for Large Load Adjustments in Forecasted \nCapacity Obligations of PJM Interconnection, L.L.C., Docket No. ER24-2447-000, at 1 (July 1, 2024). \n198 Id. \n199 NEDC/PJM Governors’ Principles at 2."},{"page":65,"startToken":21273,"endToken":21671,"text":"65 \nPJM to rely on the individual states to ultimately allocate the RBP Charges to the new data \ncenter loads on the retail level in accordance with the NEDC/PJM Governors’ Principles. \nd. \nClaims that RBP cost allocation would affect existing \ncommercial arrangements are unsupported and speculative. \nFirstEnergy asserts that PJM’s allocation of cost responsibility “violates the filed \nrate doctrine because it will undermine preexisting commercial relationships by attempting \nto allocate costs to data centers who possibly have already signed FERC-jurisdictional \ncontracts based on a pre-RBP understanding of the market.”200  This assertion is fatally \nflawed.   \nFirst, FirstEnergy fails to support it.  FirstEnergy cites no “FERC-jurisdictional \ncontracts” which would be public, to the extent they exist, that would be “undermined.”  \nThus, it is not possible to discern which filed rate would be violated.  Relatedly, FirstEnergy \npresents this as something that is “possible” not actual.  Thus, even taking the claim as \nasserted by FirstEnergy, it is speculative.   \nSecond, each contract is an exercise in risk allocation between the parties to that \ncontract.  For years, it has been well understood that the PJM Region would soon be facing \na capacity shortfall.201  \n \n200 FirstEnergy Comments and Protest at 13. \n201 See, e.g., PJM Interconnection, L.L.C., Revisions to Reliability Pricing Model, Docket No. \nER25-682-000, Transmittal Letter at 5 (Dec. 9, 2024) (“PJM expects the rapid tightening of supply and \ndemand trends to continue for the foreseeable future.  Indeed, PJM expects load growth to continue to further \nincrease even in the upcoming 2026/2027 Base Residual Auction, driven in large part by electrification trends \nand data center development in the PJM Region. Preliminary 2025 load forecast indicates a load increase of \n2,700 MW for the 2026 Delivery Year compared with the 2024 load forecast for the same 2026 Delivery \nYear.”); Tim Horger & Adam Keech, 2025/2026 Base Residual Auction Results, PJM Interconnection, \nL.L.C., \n30 \n(Aug. \n21, \n2024), \nhttps://pjm.com/-/media/committees-\ngroups/committees/mrc/2024/20240821/20240821-item-08---2025-2026-base-residual-auction---\npresentation.ashx [https://perma.cc/5WBB-WFAW] (In the 2025/2026 BRA, the market’s supply and \ndemand converged to the point where only 514 MW of annual UCAP was offered above the PJM Region \nReliability Requirement in the 2025/2026 BRA.); Energy Transition in PJM: Resource Retirements, \nReplacements & Risks, PJM Interconnection, L.L.C., 17 (Feb. 24, 2023), https://www.pjm.com/-\n/media/library/reports-notices/special-reports/2023/energy-transition-in-pjm-resource-retirements-"},{"page":66,"startToken":21671,"endToken":22064,"text":"66 \nSince at least April 2025, there has been discussion about the need for an out-of-\nRPM mechanism to address the resource adequacy shortfall caused by new large loads—\nincluding through a load reduction service for non-capacity backed loads202 or through an \n“enhanced” RPM reliability backstop mechanism “to mitigate potential for acute reliability \nrisks” as advocated by the Brattle Group in the 2025 VRR Curve periodic review \nprocess.203  Notably, the cited notices of potential future action on large loads occurred \nbefore or contemporaneous with Electric Distributors’ and LSEs’ submission of their fall \nof 2025 Load Adjustment requests to PJM204—the Load Adjustments included in the 2026 \nLoad Forecast and that comprise the Initial RBP Target. \nGiven this, LSEs and large loads should have been on notice that change was \ncoming, and as sophisticated parties, they would have priced and valued in their contractual \nnegotiations the risk of how the PJM Region and the Commission would address the \nimpacts of large loads causing the resource adequacy shortfall.  Given that these are not \npro forma arrangements, the means for allocating risk would be idiosyncratic to each \n \nreplacements-and-risks.ashx. [https://perma.cc/8UGM-9MNT ] (In light of these uncertainties, PJM’s 2023 \nwhitepaper emphasized the importance of “[m]anaging the energy transition through collaborative efforts of \nPJM stakeholders, state and federal agencies, and consumers” in order to “ensure PJM has the tools and \nresources to maintain reliability.”). \n202 Tim Horger, Large Load Additions, PJM Interconnection, L.L.C. (Sep. 15, 2025), https://www.pjm.com/-\n/media/DotCom/committees-groups/cifp-lla/2025/20250915/20250915-item-07---pjm-initial-proposal-and-\nalternatives-considered---pjm-presentation.pdf [https://perma.cc/63JH-37Q2]. \n203 Kathleen Spees, et al., Sixth Review of PJM’s Variable Resource Requirement Curve for Planning Years \n2028/29 Through 2031/32, Brattle Group, 11 (Apr. 9, 2025), https://www.brattle.com/wp-\ncontent/uploads/2025/04/Sixth-Review-of-PJMs-Variable-Resource-Requirement-Curve.pdf \n[https://perma.cc/DT9F-FJ32]. \n204 For information about the Load Adjustments submitted in 2025 for the 2026 Load Forecast, see the \nmeeting materials posted for the September 16, 2025 Load Analysis Subcommittee meeting.  See Load \nAnalysis \nSubcommittee, \nPJM \nInterconnection, \nL.L.C., \nhttps://www.pjm.com/committees-and-\ngroups/subcommittees/las [https://perma.cc/2327-9PJB] (last visited Sep. 10, 2026); see Load Analysis \nSubcommittee, Agenda, PJM Interconnection, L.L.C. (Sep. 16, 2025), https://www.pjm.com/-\n/media/DotCom/committees-groups/subcommittees/las/2025/20250916/20250916-agenda.pdf \n[https://perma.cc/38XS-EZB4]."},{"page":67,"startToken":22064,"endToken":22530,"text":"67 \ncontract.  In any event, to the extent the RBP was not contemplated by the parties, the \nbenefits of RBP—and the RBP UCAP MW—also were not contemplated.  Thus, allocation \nof RBP Charges corresponding to such benefit would be just and reasonable. \nFinally, to the extent an existing arrangement may be affected by PJM’s proposed \nRBP cost allocation, the extent to which any deal may be affected is necessarily a \ncontract-specific inquiry.   \ne. \nPJM’s proposed cost allocation rules appropriately invite \nstate input on allocating costs to specific retail customers. \nEKPC broadly objects to PJM’s cost allocation approach, and the Kentucky \nAttorney General, in support of EKPC, notes that “[o]f particular concern is whether Load \nServing Entities who have met their obligations are protected from cost allocation in the \nevent of default by the cost causer.”205  EKPC raises concerns about state regulatory bodies \nelecting whether to reallocate cost responsibility, with the root of the concern apparently \nfocused on uncertainty about whether the state regulator will act and if so, how.206   \n \n205 Kentucky Attorney General Answer at 2.  To be clear, under PJM’s proposal, in no event would EKPC \nbe allocated any cost responsibility.  EKPC would not be allocated any cost responsibility for RBP Charges, \nas the EKPC Transmission Zone and Electric Distributor zone/area did not have any Load Adjustment MW \nfor the 2026 to 2028 period.  2026 PJM Load Forecast Report Data Tables, PJM Interconnection, L.L.C., \nTab Table B9b (Feb. 2026), https://www.pjm.com/-/media/DotCom/planning/res-adeq/load-forecast/2026-\nload-report-tables.xlsx [https://perma.cc/SST2-EGUZ]; 2026 PJM Load Forecast Report, PJM \nInterconnection, L.L.C., 5-6 (Jan. 14, 2026), https://www.pjm.com/-/media/DotCom/library/reports-\nnotices/load-forecast/2026-load-report.pdf [https://perma.cc/J24E-7CV7] (describing Table B9b results).  In \nfact, under PJM’s proposal, EKPC would not be allocated any cost responsibility in the event of default by \nanother LSE on paying RBP Charges, as PJM’s proposal would require such reallocation of cost \nresponsibility among other LSEs already paying RBP Charges.  See July 31 Filing, proposed Tariff, \nAttachment DD, section 18.9(a) (“In the event a Load Serving Entity defaults and fails to pay an RBP Charge, \nthe defaulted amount will be allocated to all remaining Load Serving Entities responsible for paying RBP \nCharges based on their pro-rata share of the total RBP Charges for all such Load Serving Entities.  Such \namounts may be offset by the RBP Collateral posted by the defaulting Load Serving Entity.”).   \n206 See EKPC Protest at 17 (“The uncertainty of being assigned costs, as well as the magnitude of the costs \nthat may be assigned, should the large loads not materialize in each zone/area as PJM anticipated in \nestablishing the procurement target, will itself impact whether large loads materialize as forecasted.”)."},{"page":68,"startToken":22530,"endToken":22856,"text":"68 \nPJM’s proposal is just and reasonable in this regard—and consistent with the stated \ncommitments of all 13 governors in the PJM Region.  As explained in the July 31 Filing, \nPJM’s proposal follows the Commission’s lead by respecting the boundary between state/ \nRERRA and federal jurisdiction.207  It is the PJM states and/or RERRAs that “have \nauthority over how the wholesale costs of providing electricity, including transmission of \nsuch electricity, to those retail customers are recovered through retail rates.”208  To achieve \nthe goal of allocating RBP Charges to the data centers and other large load, the states’ line \nof sight into the retail customers and their LSEs—line of sight PJM does not have—will \nbe vital.  Thus, a cost allocation methodology that provides the PJM states and/or RERRAs \nwith the ability to determine how to allocate RBP Charge to LSEs within a given Electric \nDistributor zone/area, as well as to cost allocate to end-use customers in their respective \nstates in accordance with their laws and policies, supports each PJM state governor’s \npledge in the NEDC/PJM Governors’ Principles, including the principle that the cost of \nnew capacity should be allocated to data centers who have caused the need for additional \ncapacity in the PJM Region.209   \nEKPC also argues against the default allocation approach, which would only apply \nif a relevant state elects not to act.  Specifically, EKPC argues that “PJM has failed to \nprovide clear and transparent procedures to allow an LSE to determine the amount of costs \nit may be allocated under the PJM RBP proposal”210 and that “[t]his backup methodology \n \n207 See July 31 Filing, Transmittal Letter at 104-08. \n208 PJM Interconnection, 195 FERC ¶ 61,211 at P 69 (citing PJM Interconnection, L.L.C. v. PJM \nInterconnection, L.L.C., 190 FERC ¶ 61,115, at P 68 (2025)). \n209 NEDC/PJM Governors’ Principles at 1. \n210 EKPC Protest at 17 (internal quotation marks omitted)."},{"page":69,"startToken":22856,"endToken":23177,"text":"69 \nsocializes RBP costs across all load within the zone—including LSEs serving customer \nbases that contributed nothing to the capacity shortfall.”211 \nFirst, PJM’s proposed rules very clearly delineate how an LSE may be allocated \nresponsibility for RBP Charges in the unlikely event that the applicable state regulatory \nbody fails to weigh in.  As PJM has previously explained, the default method of allocation \nexists only as a safeguard against the unlikely event that a state regulatory body fails to act. \nShould that default methodology be needed, LSEs in Electric Distributor zone/areas \nto which some quantity of Load Adjustments have been assigned would be allocated cost \nresponsibility in the same way that cost responsibility is allocated to LSEs in the RPM.212  \nAs such, the backup method of allocation under the RBP, relied on only if state regulatory \nbodies fail to act, is an established, clear and transparent methodology.  \nSecond, in the absence of state coordination, PJM will not have the granular \ninformation needed to assign cost responsibility to the LSEs serving the retail load that \ngave rise to the Load Adjustment.  While the Load Adjustment process does allow PJM to \nreceive some data about which LSE is serving load, this does not necessarily mean that \nPJM will have all the necessary data in every instance.  Thus, under such circumstances, \nshould they arise, spreading the responsibility for RBP Charges pro-rata across an Electric \nDistributor zone/area would be a reasonable method to fall back on.   \n \n211 Id. at 20. \n212 See July 31 Filing, proposed Tariff, Attachment DD, section 18.3(b)(iii) (“If no [RBP Obligation] MW \nare reported to the Office of the Interconnection in an Electric Distributor zone/area, PJM will allocate the \nRBP Charges for that zone/area to all load in the zone/area using each LSE’s ratio share of the Daily Unforced \nCapacity Obligation for the zone/area as determined in RAA, Schedule 8.”)."},{"page":70,"startToken":23177,"endToken":23493,"text":"70 \nf. \nBecause RBP is driven by the need for all new large loads to \nbring their own capacity, to avoid RBP Charges, an Electric \nDistributor zone/area must fully offset its Load Adjustment \nMW. \nDominion asserts that PJM’s approach to crediting an Electric Distributor zone/area \nfor Qualifying RBP Offset UCAP MW is unjust and unreasonable because, for cost \nallocation purposes, PJM counts Qualifying RBP Offset UCAP MW against the Electric \nDistributor zone/area’s MW of Load Adjustments, and not against that zone/area’s \nallocated portion of the Initial RBP Target.213  While Dominion’s argument may, at first, \nappear to have some surface appeal, a closer examination reveals that Dominion’s position \nwould not support the overarching policy driving the RBP, the NEDC/PJM Governors’ \nPrinciples, and the Ratepayer Protection Pledge:  All new large loads should pay for new \ncapacity and their effects on the transmission system; conversely, existing loads should not \nbear the costs to connect and serve large loads.  Insulating existing ratepayers from the new \nand expansive demands placed on the region by the recent influx of new large loads is at \nthe heart of the NEDC/PJM Governors’ Principles and the Ratepayer Protection Pledge.  \nNaturally, this primary driver of the RBP animates PJM’s proposed cost allocation \nmethodology.  PJM’s approach to determining how an Electric Distributor zone/area may \neliminate its RBP obligation is grounded in this overarching policy, as explained below. \nFirst, while the RBP targets a 6,831.3 MW shortfall, it is the Load Adjustments that \ndrive the need for the RBP and therefore drive cost allocations to each Electric Distributor \nzone/area.  Table 1 below shows the total Load Adjustments submitted for each Electric \nDistributor zone/area for 2026 through 2028.  Table 1 was initially presented by PJM at \nthe third post-filing stakeholder workshop, held August 28, 2026, to discuss RBP \n \n213 See Dominion Partial Protest and Comments at 5-7."},{"page":71,"startToken":23493,"endToken":23727,"text":"71 \nimplementation of the RBP,214 and it is a more detailed version of the table submitted in \nMs. Croop’s affidavit.215  The Load Adjustments values during this period total \n9,033.2 MW.  Broadly speaking, these MW represent new large loads that are expected to \ncome to the PJM Region and, until PJM receives their Qualifying RBP Offset UCAP MW \nsubmissions, have not brought any new capacity.   \nTable 1: 2026-2028 Load Adjustment MW by Electric Distributor zone/area216 \n \nAs Ms. Croop explained, “[t]he initial allocation of RBP UCAP MW to each \nElectric Distributor zone/area will be based on Load Adjustments . . . and each zone/area’s \nshare of the Initial RBP Target of 6,831.3 MW.”217  In other words, an Electric Distributor \nzone/area’s MW of Load Adjustment represents that zone/area’s contribution to the need \n \n214 August 28, 2026 RBP Execution Presentation at 7.  For a complete list of all Electric Distributor \nzone/areas, even those with zero Load Adjustment MW between 2026-2028, see PJM’s presentation at the \nsecond post-filing stakeholder workshop.  PJM Staff & Charles River Associates, Reliability Backstop \nProcurement Execution, PJM Interconnection, L.L.C., 11 (Aug. 10, 2026), https://www.pjm.com/-\n/media/DotCom/committees-groups/cifp-rbp/2026/20260810/20260810-pjm-and-cra-reliability-backstop-\nprocurement-presentation.pdf [https://perma.cc/3URZ-SUXW]. \n215 July 31 Filing, Croop Aff. ¶ 46. \n216 August 28, 2026 RBP Execution Presentation at 7.  \n217 July 31 Filing, Croop Aff. ¶ 46."},{"page":72,"startToken":23727,"endToken":24035,"text":"72 \nfor the RBP.  The projected influx of new load, as represented by the Load Adjustment \nMW generally caused the resource adequacy shortfall for the 2028/2029 Delivery Year. \nOnly by eliminating their Load Adjustment MW value can an Electric Distributor \nzone/area eliminate its responsibility for RBP Charges.  Put another way, the UCAP MW \nfigures in the far-right column of Table 1 represent each Electric Distributor zone/area’s \nallocation of the Initial RBP Target.  These figures are the result of applying an Electric \nDistributor zone/area’s proportional share of the total 9,033.2 MW Load Adjustment to the \nidentified 2028/2029 Delivery Year shortfall.  In other words, each Electrical Distributor’s \ninitial allocation of the RBP target does not represent its proportional responsibility for the \nRBP; rather, it is a function of its proportional responsibility (i.e., it is a mathematically \nderived value resulting from multiplying its proportional share of the total Load \nAdjustment MW by the Initial RBP Target value).  Each Electric Distributor zone/area’s \nproportional share of the total Load Adjustment MW is a means of capturing the \nzone/area’s proportional share of the influx of new large load that is projected to come \nonline in the near future.  That influx of new load can be said to have caused the need for \nthe RBP.   \nWith this understanding and context, it becomes clear that Dominion’s critique of \nPJM’s default method for allocating RBP Charges misses the mark.  First, Dominion claims \nthat “[r]equiring [Electric Distributor] zone/areas to offset their entire MW Load \nAdjustment Share to avoid having an RBP Obligation raises the possibility that they will \npay for redundant capacity, which is unjust and unreasonable.”218  The fact is that the Load \nAdjustment represents the quantity of new large loads that have not brought new capacity, \n \n218 Dominion Partial Protest and Comments at 6."},{"page":73,"startToken":24035,"endToken":24357,"text":"73 \nand each Electric Distributor zone/area’s share of the Load Adjustment represents that \nzone/area’s responsibility for the shortfall giving rise to the RBP.   \nNevertheless, PJM proposed that new loads in a zone/area can be demonstrated to \nhave since brought new capacity by being matched with Qualifying RBP Offset UCAP \nMW.  Thus, the Initial RBP Target may be decremented by the quantity of Qualifying RBP \nOffset UCAP MW.  Such a requirement does not lead to “redundant capacity;” it leads to \nnew capacity serving new large loads.  Qualifying RBP Offset UCAP MW can extinguish \nthe Electric Distributor zone/area’s contribution to the need for the RBP.  Further, requiring \nall new large loads to “build, bring, or buy the new generation resources and electricity \nneeded to satisfy their new energy demands” is required by the Ratepayer Protection Pledge \nand allows all existing capacity resources to be available to serve non-new large loads. \nDominion also argues that PJM’s approach could result in some LSEs/new large \nloads in some Electric Distributor zone/areas bringing on sufficient new capacity to \neliminate the entirety of the Final RBP Target such that load in Electric Distributor \nzone/areas “that did not bring RBP Offsets will still have remaining MW Load Adjustment \nShares but will not bear any financial consequences for not bringing RBP Offsets because \n[the] Final RBP Obligation will be 0 MW[.]”219  The fact that the actions of some LSEs or \nloads may reduce the RBP obligations of others is not inherently unjust and unreasonable.  \nThe diffuse benefit from pooled resources is a key feature of being in an RTO.  Further, to \nthe extent some LSEs and/or new large loads in some Electric Distributor zone/areas were \nto zero-out the entirety of the Initial RBP Target by bringing on sufficient new capacity to \nmeet that target, LSEs and/or new large loads in Electric Distributor zone/areas with Load \n \n219 Id. at 7."},{"page":74,"startToken":24357,"endToken":24695,"text":"74 \nAdjustment MW not matched with new capacity would be foreclosed from being assigned \ncost responsibility through the RBP.  However, those LSEs and/or new large loads would \nnevertheless still be required to bring new capacity or provide IRAS, outside of the RBP \nframework.   \nJ. \nPJM Appropriately Tailored the Buyer-Side Credit Requirement to the \n15-year Forward Risk Presented By the RBP Commitments So As to \nProtect Ratepayers from Bearing Costs for RBP Resources. \n1. \nPJM’s buyer-side (LSE) collateral requirement is appropriately \ndesigned to protect ratepayers from exposure to RBP Charges and \nensure large loads bear RBP Resource costs, as required by the \nRatepayer Protection Pledge and NEDC/PJM Governors’ \nPrinciples, and consistent with PJM’s existing credit rules. \nA handful of entities take issue with PJM’s proposal to require those LSEs who \ncontributed to the current resource adequacy shortfall that RBP is designed to address to \npost collateral for the purpose of protecting all other ratepayers in PJM from bearing the \ncosts of RBP Resources.220  One protestor questions “why it is necessary to require LSEs \nto post additional collateral” to cover their 15-year RBP charge obligation, asserting that \n“there is no justification for imposing new and onerous collateral requirements on LSEs,” \n“[b]ecause retail customers ultimately will pay the RBP costs.221   \nWhile PJM understands that arguments can be made over the amount of collateral \nrequired, the basic need for a collateral requirement should not be controversial.  Imposing \na credit requirement for the purpose of ensuring only those entities assigned cost \nresponsibility for RBP Resources bear the burden of such costs protects “those LSEs not \n \n220 See NOVEC Protest at 19-24; EKPC Protest at 21-28; FirstEnergy Comments and Protest at 7-9; Equinix \nComments at 14-16.  No party challenges PJM’s proposed RBP Seller credit requirement.  Equinix describes \nit in passing.  See Equinix Comments at 14.  EKPC’s affiant, Carl F. Coscia, Ph.D., offers criticisms about \nthe process but not the merits.  See EKPC Protest, Affidavit of Carl F. Coscia (Attachment 2) ¶¶ 182-84. \n221 FirstEnergy Comments and Protest at 7-8."},{"page":75,"startToken":24695,"endToken":25002,"text":"75 \nallocated cost responsibility for RBP Resources from having to pay for such resources.” 222  \nThis is consistent with the purpose of PJM’s existing credit rules, which the Commission \nhas recognized is to “protect the integrity of the PJM-administered markets, as well as \nprotect market participants from financial losses that result from unreasonable credit risks \nand defaults.”223  PJM’s proposal implements the NEDC/PJM Governors’ Principles and \nRatepayer Protection Pledge by “allocat[ing] the cost of any new capacity procured through \nthe . . . Reliability Backstop [Procurement] to load serving entities (LSEs) with new data \ncenters,”224 so as to “protect American consumers from price hikes due to data center \nenergy and infrastructure requirements, and lower electricity costs for consumers in the \nlong term.”225 \nIndeed, PJM designed RBP to provide a key role for the states, consistent with their \ngovernors’ commitment in the NEDC/PJM Governors’ Principles to “use all available \nauthorities to ensure that their state public utility commissions . . . ensure that their states’ \nLSEs allocate their share of the cost to procure new capacity through the Reliability \nBackstop [Procurement] to new data center loads,” i.e., the loads that comprise the Load \nAdjustments driving the current capacity shortfall.226  The NJ BPU, for one, recognizes the \nimportant role the state will have in ensuring RBP costs (including costs associated with \ncredit requirements) are properly allocated.  In its comments supporting PJM’s proposal, \nthe NJ BPU correctly observes that “[i]n theory, an LSE would pass on the collateral costs \nto the large load, but there may need to be additional forcing mechanisms [at the state level] \n \n222 July 31 Filing, Transmittal Letter at 114. \n223 PJM Interconnection, L.L.C., 171 FERC ¶ 61,173, at P 36 (2020). \n224 NEDC/PJM Governors’ Principles at 1 (emphasis omitted). \n225 Ratepayer Protection Pledge.  \n226 NEDC/PJM Governors’ Principles at 2."},{"page":76,"startToken":25002,"endToken":25326,"text":"76 \nin restructured states where retail choice and default service has been the assumed retail \nsystem.”227  The NJ BPU continues that the proposed “collateral requirement will put \npressure on the retail-jurisdictional authorities to ensure the collateral obligation does not \nfall upon ratepayers.”228  PJM shares this objective of acting to prevent ratepayers from \nbearing RBP costs, and stands ready to work with the states to develop all appropriate \nmechanisms so that large loads bear all RBP costs. \nFinally, contrary to protestors’ claims otherwise,229 PJM’s proposal also is \nconsistent with cost causation principles,230 as the LSEs serving the new load captured by \nthe Load Adjustments for which PJM was unable to procure capacity in the 2028/2029 \nBRA are the entities that caused the need for the RBP and the entities to be allocated \nresponsibility to pay RBP Charges.  Given that the credit requirements apply only to those \nLSEs allocated responsibility for RBP Charges, the credit obligation is directly tied to the \nentity from whom there is default risk exposure, thus appropriately protecting all other \nentities from paying RBP Charges. \n2. \nPJM’s proposed RBP credit requirement is not duplicative of any \nexisting PJM credit rule but, rather, is tailored to the long-term \nobligation to pay RBP Charges, which is unlike any current payment \nobligation in PJM’s market rules.  \nEKPC and NOVEC both claim that this collateral is “duplicative” of the Peak \nMarket Activity collateral PJM requires with regard to, generally speaking, a Market \nParticipant’s transaction activity in PJM’s capacity, energy, and ancillary services markets \n \n227 NJ BPU Comments at 5-6. \n228 NJ BPU Comments at 6. \n229 See, e.g., NOVEC Protest at 10; EKPC Protest at 28. \n230 See N. States Power Co., 64 FERC ¶ 61,324, at 63,379 (“[T]he fundamental principle of cost causation \n[is] that costs should be recovered in the rates of those customers who utilize the facilities and thus cause the \ncost to be incurred.”)."},{"page":77,"startToken":25326,"endToken":25726,"text":"77 \nand for transmission service.231  Protestors are correct that PJM’s proposed collateral \nrequirements do not “bear[] any relation” to PJM’s current collateral requirements.232  The \nlong-term, up to 15-year payment obligation to RBP Resources is unlike any other \ncommitment in PJM.  As such, the credit requirement for the long-term RBP committed \nobligation should be different from the credit requirements for PJM’s capacity and energy \nmarkets and transmission services.   \nCurrently, PJM utilizes the Peak Market Activity metric to determine the \nappropriate credit requirement for each LSE buyer of transmission, capacity, energy, and \nancillary services.  Generally, PJM requires LSEs to maintain credit based on the greatest \namount invoiced on a rolling period of one, two, three, or four weeks.233  To be clear, Peak \nMarket Activity is a backward-looking metric that is used to determine the amount of credit \nneeded to protect PJM’s markets and Members from default of amounts owed for \nobligations delivered.   \nPeak Market Activity’s rolling basis for the credit requirement makes sense for \nthese products.  PJM’s capacity markets procure forward capacity commitments, and \nassociated LSE buyer obligations, on a year-by-year basis.  But, PJM does not have any \n \n231 NOVEC Protest at 22; see EKPC Protest at 23 (“[T]he same obligation is also collateralized twice.  The \nRBP Charge is secured in advance by the Credit Rate, and once the Delivery Year begins and RBP Charges \nare billed, those same charges enter the LSE’s Peak Market Activity through the ordinary operation of \n[Tariff,] Attachment Q and are secured again.”). \n232 See EKPC Protest at 26. \n233 See Tariff, Attachment Q, section VII.A; see PJM Interconnection, L.L.C., 186 FERC ¶ 61,055, at P 3 \n(2024) (“Peak Market Activity is one of the tools that PJM utilizes to determine a market participant's risk \nexposure and the level of financial security required to support that market participant’s activity in the PJM \nmarkets.  Under the Tariff, PJM must calculate the Peak Market Activity for each participant to determine \nhow much credit or collateral the participant must provide to PJM to participate in the PJM markets.  Peak \nMarket Activity is calculated based on invoices for the market participant’s transaction activity in all PJM \nMarkets, excluding FTR Net Activity, Virtual Transactions Net Activity, and Export Transactions Net \nActivity.  To satisfy its Peak Market Activity credit requirement, each participant must maintain a sufficient \nunsecured credit allowance and/or collateral, as applicable.” (footnotes omitted))."},{"page":78,"startToken":25726,"endToken":26136,"text":"78 \nrules specific to the credit risk associated with the LSE buyers’ obligation to pay capacity \ncharges throughout the year; rather, such are captured in Peak Market Activity, and to the \nextent an LSE defaults on its obligations, the provider of last resort for that load becomes \nresponsible on a going-forward basis.   \nIn contrast, PJM envisions that an LSE’s obligation to pay RBP Charges should not \nbe shunted to a provider of last resort—the idea is that the large load driving the need for \nthe RBP should bear these costs—through its LSE, consistent with the Ratepayer \nProtection Pledge.  Once assigned cost responsibility, an LSE should assume that it will be \nresponsible for paying RBP Charges through the remainder of the term, i.e., through the \nend of the 2042/2043 Delivery Year.234  Thus, the RBP cost allocation and credit \nrequirements are fundamentally different from PJM’s existing capacity payment \nobligations, and comparisons to Peak Market Activity, and its rolling-based credit \nrequirement, are accordingly misplaced.235 \nIn sum, Peak Market Activity and the proposed RBP credit requirement serve two \ndifferent purposes and track different types of financial exposure.  The core difference is \nwhat they measure.  Peak Market Activity manages immediate, rolling operational risk \nfrom daily transactions based upon a rolling, backward-looking billing history.  In contrast, \nthe proposed RBP credit requirement is to cover forward-looking risk over a long-term, up \n \n234 There appears to be some confusion about when the collateral requirements would need to be posted and \nhow much would need to be posted for a given Delivery Year.  See Constellation Protest at 16.  PJM therefore \nclarifies that an LSE-allocated responsibility for paying RBP Charges does not need post collateral until 45 \ndays “[p]rior to the first Delivery Year” it is responsible for paying RBP Charges.  See July 31 Filing, \nproposed Tariff, Attachment DD, section 18.8(b).  And, the amount of collateral required would be based on \nthe RBP UCAP MW committed for that Delivery Year.  Id., proposed Tariff, Attachment DD, \nsection 18.8(b)(i)(A) (“The cumulative RBP credit requirement for Load Serving Entities for a given \nDelivery Year shall be equivalent to the product of the RBP Credit Rate multiplied by RBP UCAP MW \ncommitted . . . . ”).  In other words, no collateral would be required for RBP Resources are not in service for \nthat Delivery Year, and no RBP Charges would be assessed.  \n235 See EKPC Protest at 26; id., Coscia Affidavit ¶¶ 25-29; Equinix Comments 14-16."},{"page":79,"startToken":26136,"endToken":26395,"text":"79 \nto 15-year commitment to sellers.  Thus, it is clear that the RBP credit requirement is not \n“duplicative” of Peak Market Activity, as protestors claim.   \n3. \nPJM’s proposed LSE credit requirement is properly tailored to \ncover long-term payment obligation and protect ratepayers from \nexposure to RBP Charges.   \nA few protestors contend that PJM’s proposal LSE credit requirement is \n“unnecessary” and “excessive.”236  In variations on these themes, FirstEnergy argues that \n“PJM must be able to show that its proposed collateral requirements are reasonably tailored \nto the actual credit risk presented by specific LSEs, or substantially similar classes of \nLSEs;”237 EKPC argues that it was not “derived from measured exposure;”238 and NOVEC \nargues that “at the most, RBP buyers should only have to provide collateral for the \nincremental cost of the RBP clearing price above the weighted RPM clearing price for the \nrelevant Delivery Year.”239  Each of these arguments misses the mark. \na. \nThe LSE RBP credit requirement is necessary to protect \nratepayers. \nAs an initial matter, PJM’s proposed credit requirement definitely is not \n“unnecessary.”  Without a properly designed credit requirement, other ratepayers (i.e., \nthose not associated with the large loads causing the need for the RBP and the RBP \nResources) would be exposed to paying for these resources.  To minimize other ratepayers’ \nexposure to RBP Charges, RBP Charge payment obligations must be properly \n \n236 NOVEC Protest at 19; FirstEnergy Comments and Protest at 7; Equinix Comments at 14. \n237 FirstEnergy Comments and Protest at 8. \n238 EKPC Protest at 23. \n239 NOVEC Protest at 22."},{"page":80,"startToken":26395,"endToken":26835,"text":"80 \ncollateralized such that all default risk rests with those allocated RBP cost responsibility.240  \nAs discussed, this should not be controversial.   \nb. \nThe LSE RBP credit requirement is objective, not unduly \ndiscriminatory, and just and reasonable. \nContrary to FirstEnergy’s claims,241 PJM’s approach of treating each LSE-\nallocated cost responsibility equally, in an open and transparent manner, is just and \nreasonable.  Ms. Gwen Kelly, PJM’s Senior Director, Credit Risk and Collateral \nManagement, testified that “PJM considered that the relevant financial exposure is created \nby the portfolio of committed RBP resources rather than by any individual LSE in \nisolation.”242  PJM looked at the forward obligation to the RBP Resources instead of \nindividual LSE’s creditworthiness and ability to pay for a couple of reasons.  One, this \nprovided the best approach for protecting other ratepayers from exposure to RBP Charges.  \nThat is, by looking at the obligation and not the payor, PJM can better devise credit rules \nto safeguard the payment and reduce exposure in case of default.   \nTwo, this approach would allow for a uniform credit rate applicable to each \nallocated RBP UCAP MW.  As such, PJM has proposed an “objective, transparent, and \n \n240 See July 31 Filing, proposed Tariff, Attachment DD, section 18.9(a) (“In the event a Load Serving Entity \ndefaults and fails to pay an RBP Charge, the defaulted amount will be allocated to all remaining Load Serving \nEntities responsible for paying RBP Charges based on their pro-rata share of the total RBP Charges for all \nsuch Load Serving Entities.  Such amounts may be offset by the RBP Collateral posted by the defaulting \nLoad Serving Entity.”).  In the July 31 Filing, PJM inadvertently described how the allocation of LSE defaults \non RBP Charges would be treated.  PJM correctly described the management of LSE defaults at Part III.F.5, \nexplaining that “upon any LSE’s default of RBP Charges, the defaulted amounts shall be reallocated to among \nthe other LSEs allocated RBP Charges based on their proportional share of the total RBP Charges assessed \nacross the PJM Region.”  July 31 Filing, Transmittal Letter at 122 (citing id., proposed Tariff, Attachment \nDD, section 18.9(a)).  However, PJM misdescribed how the management of LSE defaults in Part III.C.10, \nand the Commission should ignore that redundant and incorrect discussion in the July 31 Filing. \n241 See FirstEnergy Comments and Protest at 8 (PJM’s proposal is unjust and unreasonable “because it \nautomatically treats [LSEs] as presenting the same nonpayment risk as LSEs without comparable cost \nrecovery mechanisms.”). \n242 July 31 Filing, Affidavit of Gwen Kelly on Behalf of PJM Interconnection, L.L.C. (Attachment D) ¶ 21 \n(“Kelly Aff.”)."},{"page":81,"startToken":26835,"endToken":27110,"text":"81 \nconsistent means of allocating the aggregate collateral requirement among the LSEs \nresponsible for the underlying payment obligations.”243  A uniform approach ensures \nnon-discriminatory credit requirements for all LSEs allocated cost responsibility, and each \nLSE-allocated cost responsibility for RBP Charges is required to post collateral \nproportional to its allocated share of the RBP portfolio.  To implement this approach, “PJM \ndeveloped a methodology that first determines the aggregate collateral necessary to address \nthe payment exposure associated with the portfolio of committed RBP Resources and then \nallocates that collateral requirement among the LSEs responsible for payment of RBP \nCharges.”244   \nThree, PJM’s approach is just and reasonable when considering the alternative.  \nEvaluating the creditworthiness of each LSE serving these new large loads over a \ncommitment period of up to 15 years would not provide the same level of assurance of \npayment of RBP Charges over the entire period.  That is, today’s assessment that one LSE \nis financially strong may not tell PJM much about its ability to continue to pay RBP \nCharges many years from now.  In addition, such an approach would fail to ensure \nsufficient credit to cover RBP Charges in the event the LSE goes out of business during \nthe payment term.  Indeed, the credit quality of an LSE can change considerably during a \n15-year term.  A company with investment-grade credit may suffer financial set backs \nduring the period, and have worsening credit as a result.  S&P Global, a credit rating agency \nand financial data and research company, tracks the probability of a credit rating \ntransitioning from one rating to another over a specific timeframe.  For present purposes, \n \n243 Id. ¶ 23. \n244 Id. ¶ 22."},{"page":82,"startToken":27110,"endToken":27461,"text":"82 \nPJM extrapolated S&P Global’s 10-year credit mitigation table245 to reflect a 15-year \nperiod.  The results are shown in Table 2 below.  \nTable 2: 15-year Credit Migration Table \n15 Year \n(no-NR) \nnormalized AAA \nAA \nA \nBBB \nBB \nB \nCCC/C D \nAAA \n23.1% 44.8% 22.3% 6.3% \n0.9% \n0.6% \n0.1% \n2.0% \nAA \n1.8% \n31.8% 44.6% 15.2% 2.6% \n1.1% \n0.1% \n2.8% \nA \n0.3% \n7.5% \n49.9% 29.7% 5.4% \n2.1% \n0.3% \n4.8% \nBBB \n0.1% \n1.8% \n20.7% 50.2% 11.1% 4.7% \n0.4% \n11.0% \nBB \n0.0% \n0.4% \n4.9% \n22.2% 21.4% 12.9% 1.2% \n36.9% \nB \n0.0% \n0.1% \n1.2% \n6.1% \n11.0% 12.1% 1.2% \n68.2% \nCCC/C \n0.0% \n0.0% \n0.4% \n1.7% \n3.0% \n2.6% \n0.3% \n92.0% \nD \n0.0% \n0.0% \n0.0% \n0.0% \n0.0% \n0.0% \n0.0% \n100.0% \n \nAs can be seen, PJM estimates an 11% likelihood that an entity with investment-grade \ncredit rating of BBB could transition to default status (D rating), while an entity with a BB \nrating would have a 36.9% likelihood.  In the scenario where an alternative, \nspecific-LSE-driven credit approach is used in place of PJM’s proposed obligation-focused \napproach, such declining creditworthiness would require PJM to request more and more \ncollateral from such entities in order to compensate for the increasing default risk.  As a \nmatter of practice, PJM seeks to avoid scenarios where it is exposed to declining \ncounterparty credit quality.  Given the foregoing, PJM’s proposed methodology is just and \nreasonable, as it is based on the committed obligation itself and avoids having the adequacy \nof the credit protection depend upon long-range predictions about individual LSE’s \nfinancials. \n \n245 See Default, Transition, and Recovery: 2025 Annual U.S. Corporate Default And Rating Transition Study, \nS&P Global Inc. (June 12, 2026), https://www.spglobal.com/ratings/en/regulatory/article/default-transition-\nand-recovery-2025-annual-us-corporate-default-and-rating-transition-study-s101688003 \n[https://perma.cc/7LTL-J8SQ]."},{"page":83,"startToken":27461,"endToken":27720,"text":"83 \nc. \nConsistent with the Commission’s credit policy, the \nProposed LSE RBP credit requirement is properly tailored \nto protect other ratepayers from RBP Charges. \nContrary to EKPC’s and NOVEC’s arguments,246 PJM’s proposed credit \nrequirement is not excessive but is in fact properly tailored to mitigate the risk associated \nwith RBP commitments throughout the up to 15-year RBP commitment term and therefore \nis derived from the measured forward exposure of the RBP Charges.  As Ms. Kelly \ntestified, “PJM evaluated the credit tools needed to mitigate potential defaults from \nnon-payment of RBP Charges,” and “found that its current credit tools do not contemplate \nthe long-term nature of RBP and the risk of future non-payment that results.”247  Indeed, \nPJM’s current credit tools—primarily, Peak Market Activity—are geared for recovery of \nobligations provided, i.e., for energy and capacity that was provided, and are not designed \nto project for future obligations.   \nAccordingly, “PJM evaluated methodologies for determining the amount of \ncollateral required from LSEs.”248  PJM determined that “a methodology that first \ndetermines the aggregate collateral necessary to address the payment exposure associated \nwith the portfolio of committed RBP Resources and then allocates that collateral \nrequirement among the LSEs responsible for payment of RBP Charges”249 would \neffectively obtain sufficient collateral to protect other ratepayers from shouldering the \nburden of the RBP Resources procured to address the capacity needs of the large loads \ndriving the current shortfall.   \n \n246 See NOVEC Protest at 19-24; EKPC Protest at 21-23. \n247 July 31 Filing, Kelly Aff. ¶ 19. \n248 Id. ¶ 21. \n249 Id. ¶ 22."},{"page":84,"startToken":27720,"endToken":28084,"text":"84 \nPJM’s proposal is consistent with the Commission’s credit policy, which requires \n“a reasonable balance between protecting PJM’s markets and its members against the risk \nof default and ensuring that market participants have adequate flexibility to manage their \ncollateral requirements.”250  This balance must recognize that “as more credit risk is \ntolerated, PJM is more likely to experience collateral shortfalls and, in turn, defaults,”251 \nwhich are borne by PJM Members.252  On the other hand, the Commission has cautioned \nthat “overly conservative collateral requirements or collateral requirements that are poorly \ncorrelated to credit risk can impose costs that undermine a well-functioning, efficient \nmarket by reducing liquidity and creating barriers to market participation.”253  This analysis \nshould also consider the relative risk level of such participation and the payment obligation \nbeing collateralized.  Thus, just and reasonable credit rules “correlate the . . . credit \nrequirement with the credit risk.”254  As proposed, PJM’s approach balances the protection \nof Members against the effects of LSE default and appropriately correlating the credit \nrequirement with credit risk by “establish[ing] an initial level of collateral that provides \ncommensurate protection against non- payment while avoiding full collateralization of the \nentire 15-year contractual commitment.”255 \n \n250 PJM Interconnection, 186 FERC ¶ 61,055 at P 27.   \n251 Id. P 28 & n.63 (citing Credit Reforms in Organized Wholesale Electric Markets, Order No. 741, 133 \nFERC ¶ 61,060, at P 2 (2010) (“[I]f more risk is tolerated and access to credit is too easy to obtain, then the \nmarket is more susceptible to defaults and customers bear the burden of the costs that flow from such \ndefaults.”), order on reh’g, Order No. 741-A, 134 FERC ¶ 61,126, reh’g denied, Order No. 741-B, 135 FERC \n¶ 61,242 (2011)). \n252 See Operating Agreement, section 15.2.2. \n253 PJM Interconnection, 186 FERC ¶ 61,055 at P 28 (citing Order No. 741, 133 FERC ¶ 61,060 at P 2 (“[I]f \nmore risk is tolerated and access to credit is too easy to obtain, then the market is more susceptible to defaults \nand customers bear the burden of the costs that flow from such defaults.”). \n254 Id. P 29. \n255 July 31 Filing, Kelly Aff. ¶ 24."},{"page":85,"startToken":28084,"endToken":28340,"text":"85 \nd. \nLetters of credit and cash are appropriate forms of collateral.  \nNOVEC complains that “PJM should permit NOVEC to satisfy all or a substantial \nportion of the requirement through unsecured credit or another demonstration of \ncreditworthiness rather than requiring cash collateral or a letter of credit for the full notional \namount,” implying that its “investment-grade credit rating, financial condition, and \nestablished record of satisfying its PJM obligations,” should afford it different treatment.256  \nHowever, as discussed in the July 31 Filing, PJM purposefully chose to limit the forms of \ncollateral to Letters of Credit and cash.257  PJM considered the unsecured credit available \nfrom existing Market Participants.  But, PJM’s experience—predominantly from hot and \ncold weather events—has shown that, generally speaking, Market Participants used their \nfull amount of unsecured credit to cover their Peak Market Activity credit obligations \nassociated with those periods.  Further, as discussed above, there is a likelihood that even \nentities with investment grade credit may see their financial condition deteriorate over 15 \nyears.  In such event, the entity’s access to access to liquidity may also evaporate, making \nit functionally unable to post additional collateral precisely when default risk rises.  To \ninsulate against this downward spiral, the exclusion of unsecured credit and requirement \nfor upfront collateral is prudent risk management.  As such, PJM determined that, as a \ngeneral rule, there would not be sufficient unsecured credit available from these LSEs to \ncover the up-to 15-year forward credit obligation. \n \n256 NOVEC Protest at 24. \n257 See July 31 Filing, Transmittal Letter at 109-10."},{"page":86,"startToken":28340,"endToken":28724,"text":"86 \n4. \nGiven that the Peak Market Activity is not duplicative of the LSE \nRBP credit requirement, claims that the RBP Credit Rate should be \nreduced because RBP Charges are contracts for differences lack \nmerit. \nEKPC and NOVEC argue that the credit requirement should be reduced to reflect \nthe fact that the RBP Charges will be only for the difference between [the MW-weighted \naverage of the levelized procurement cost of all selected RBP Sell Offers] and [the \nweighted average RPM clearing price for the Delivery Year] and not just for the weighted \nRBP price.  These arguments miss the mark.  At root, these claims are based on the false \npremise that the RBP credit requirement is duplicative of PJM’s Peak Market Activity, and \ntherefore there would be no need to secure collateral for the full-forward payment \nobligation.258   \nHowever, as demonstrated above, the backward-looking Peak Market Activity \napproach is not adequate for collateralizing the up to 15-year forward obligation presented \nby RBP Charges.259  Given that the RBP is to address the capacity shortfall from the \n2027/2028 and 2028/2029 RPM Auctions, which is primarily driven by the unprecedented \naddition of large loads (in the form of Load Adjustments), the loads causing the RBP—\nthrough their LSEs—should bear the costs of the RBP Resources throughout the full term.  \nThey will pay for their RPM capacity payments, as part of the pool of capacity \ncommitments, plus the RBP Charges based on the contract for differences.  That is, for \neach Delivery Year, these LSEs will pay the full MW-weighted average of the levelized \n \n258 See, e.g., EKPC Protest at 25; NOVEC Protest at 21-22. \n259 To clarify that Peak Market Activity is not an adequate credit tool for RBP Charges, PJM consents to \nrevising July 31 Filing’s proposed Tariff, Attachment DD, section 18.8 to remove the sentence:  “In addition, \nsettlement during any Delivery Year of cleared positions resulting from, or expected to result from, the \nReliability Backstop Procurement may be included, as appropriate, in Peak Market Activity pursuant to \nTariff, Attachment Q, Section VII.A.”  PJM recognizes that this sentence could cause confusion that RBP \nCharges may be captured in the Peak Market Activity credit tool, and therefore its omission from the accepted \nlanguage would facilitate proper understanding of the RBP Credit rules."},{"page":87,"startToken":28724,"endToken":29028,"text":"87 \nprocurement cost of all selected RBP Sell Offers for the RBP Resources and not just the \ncontract for differences amount.  Because the Peak Market Activity does not prospectively \ncollateralize the RPM component over the up to 15-year term, PJM requires a separate \ncredit tool to cover the forward RPM obligation and the forward RBP Charge obligation.  \nThe sum of these obligations will be known after the RBP closes (i.e., the weighted RBP \nprice) and can be straightforwardly used to determine the credit requirement.  Conversely, \nconsidering only the contract for differences amount—which are unknown and \nunknowable for each of the up to 15 Delivery Years—would needlessly over-complicate \nthe exercise without any concomitant benefits because these LSEs must pay the full amount \nregardless.  And, as a result, those LSEs should be required to post collateral sufficient to \nshield other ratepayers from their default risk, without the credit requirement being too \nhigh.   \nPJM’s proposal accomplishes this objective.  As Ms. Kelly testified, “PJM \nconcluded that an initial credit rate of $1.5 million per committed RBP MW would \ncollateralize approximately 50% of the estimated contractual value associated with the \ncommitment.”260  PJM’s proposal allows for the credit rate to decrease “when changes in \nthe underlying RBP commitment portfolio demonstrate that previously required collateral \nexceeds the remaining expected payment exposure.”261   \n \n260 July 31 Filing, Kelly Aff. ¶ 26 (emphasis added). \n261 Id. ¶ 30; see id., proposed Tariff, Attachment DD, section 18.8(b)(i)(A) (“[T]he RBP Credit Rate shall \nequal $1.5 million, as may be reduced, for reasons including a change in the total committed RBP UCAP \nMW, when total posted RBP Collateral is greater than the total remaining RBP Charges obligations, over \ntime by the Office of the Interconnection to an amount sufficient to cover the total existing RBP Charges \nobligations . . . .”)."},{"page":88,"startToken":29028,"endToken":29375,"text":"88 \nSeveral entities raised questions as to whether an initial RBP Credit Rate of \n$1.5 million per RBP UCAP MW is the best value.262  PJM has demonstrated that this \nvalue is just and reasonable and supported by substantial evidence.263  This value is keyed \nto a potential outcome of the RBP, the maximum MW-weighted average of the levelized \nprocurement cost of all selected RBP Sell Offers of $555/MW-day, and represents about \n50% of the notational contract value at that price.264  These are more than reasonable \nassumptions to properly protect other ratepayers from RBP Charges.  Indeed, the 50% of \nthe notational contract value serves the same balancing principle articulated in the \nCommission’s credit policy.  It represents approximately 50% of a quantifiable potential \ncontractual exposure, rather than full collateralization, and can decline as the remaining \nexposure declines. This calibration undermines claims that the amount is excessive or \ninsufficiently correlated to credit risk.  Plus, should the weighted average clearing price be \nlower than the $555/MW-day, PJM likely would be able to return collateral earlier.   \n5. \nLSEs contracting with new large loads are requiring collateral that \ncan be used to meet PJM’s LSE RBP credit requirement.  \nSome protestors asserted that the proposed initial RBP Credit Rate of $1.5 million \nper MW would affect their business,265 but such claims ignore the fact that standard \nbusiness practices for LSEs signing up new large loads include requiring collateral.   \nNOVEC argues that PJM’s proposed LSE credit requirement would “disrupt \nNOVEC’s ordinary business operations,” and that “[t]he Commission should not approve \n \n262 See, e.g., NOVEC Protest at 19-24; FirstEnergy Comments and Protest at 9. \n263 See July 31 Filing, Transmittal Letter at 114-22; see id., Kelly Aff. ¶¶ 24-33; see also, e.g., Papago Tribal \nUtil. Auth. v. FERC, 723 F.2d 950, 957 (D.C. Cir. 1983) (finding that the Commission’s rate “was just and \nreasonable [and] did not amount to a finding that every other rate of return was not”). \n264 See July 31 Filing, Kelly Aff. ¶¶ 25-28. \n265 See, e.g., NOVEC Protest at 20."},{"page":89,"startToken":29375,"endToken":29730,"text":"89 \na collateral requirement that is an impossibility, a hindrance to an entity’s ability to operate, \nand an injustice.”266  NOVEC states that based on its ~19% share of the RBP Target \namount, i.e., ~19% of the new large loads that caused the current shortfall,267 and PJM’s \nproposed credit rate, NOVEC’s collateral would be about $1.95 billion.  NOVEC \ncomplains that this would be “an extraordinary imposition.”268   \nThe Commission should look at NOVEC’s concerns in context.  The entire PJM \nRegion is facing a capacity shortfall because entities like NOVEC contracted to serve new \nlarge loads on an unprecedented scale at an extremely rapid pace—without requiring any \nassociated new capacity.  Indeed, according to NOVEC’s Load Adjustment presentation at \nPJM’s September 16, 2025 Load Analysis Subcommittee, NOVEC’s actual load grew from \nabout 1,204 MW in 2019 to 2,368 MW in 2025, with data centers comprising all or nearly \nall of that growth.269  NOVEC’s own near-term forecast shows that it planned to add over \n40 new data centers to its load between 2026 to 2028, increasing its contracted capacity \nfrom ~3,000 MW in 2025 to ~6,350 MW in 2028.270   \nAs for NOVEC’s collateral requirement, the underlying idea is that the large loads \nit serves should bear these costs.271  Of course, the Commission and PJM cannot dictate \n \n266 NOVEC Protest at 20. \n267 See July 31 Filing, Croop Aff. ¶ 46. \n268 NOVEC Protest at 20. \n269 PJM Load Analysis Subcommittee, NOVEC Data Center Load Forecast, Northern Virginia Electric \nCooperative, \n4 \n(Sep. \n16, \n2025), \nhttps://www.pjm.com/-/media/DotCom/committees-\ngroups/subcommittees/las/2025/20250916/20250916-item-04b---novec-large-load-request.pdf \n[https://perma.cc/ZJD5-36Y6] (“NOVEC Data Center Load Forecast”). \n270 NOVEC Data Center Load Forecast at 15.  \n271 FirstEnergy alleges that the collateral costs “will ultimately be borne by retail ratepayers” and “harm retail \ncustomers.”  FirstEnergy Comments and Protest at 8-9.  PJM believes that the large loads driving the Load \nAdjustment should be allocated any costs of posting the necessary collateral, not other ratepayers.  The \nallocation of such costs among an LSE’s ratepayers is a matter within the state’s jurisdiction."},{"page":90,"startToken":29730,"endToken":30211,"text":"90 \nthe terms of the retail tariffs to require NOVEC to pass these costs to its large loads,272 and \nPJM does not seek to do so here.  NOVEC has testified before the Virginia State \nCorporation Commission that its contracting practices with large loads include “strict credit \nreview and collateral requirements” and “NOVEC has been very successful at putting \ncredit protection instruments in place that offer a variety of solutions available to different \ntypes of data center customers.”273  Presumably, the collateral posted by NOVEC’s data \ncenter customers could be used to meet the RBP credit requirements.274 \nMore broadly, the Credit Support Annex of the International Swaps and Derivatives \nAssociation (“ISDA”) Master Agreement supports the notion that these LSEs serving large \nloads should have required collateral from their customers that could be contributed toward \nmeeting the RBP collateral requirement.  To the extent the LSE relied on the ISDA Master \nAgreement, paragraph 6(c)(i) of the Credit Support Annex allows the LSE to use the large \nload’s collateral toward meeting the LSE’s collateral requirements.275 \nFurther, other LSEs in the PJM Region are imposing strong collateral requirements \nin their contracts serving large loads.  Generally, it appears that utilities are designing the \n \n272 See Tri-State Generation & Transmission Ass’n, 193 FERC ¶ 61,070, at P 52 (2025). \n273 Ex Parte: Electric Utilities and Load Growth, Case No. PUR-2024-00144, Opening Remarks of Gilbert \nD. Jaramillo on Behalf of Northern Virginia Electric Cooperative, at 4 (Va. S.C.C. Dec. 16, 2024), \nhttps://www.scc.virginia.gov/docketsearch/DOCS/82vs01!.PDF [https://perma.cc/2ZRP-3UYA]. \n274 Regardless, NOVEC would not be without options.  For example, as NOVEC is rate regulated by the \nVirginia State Corporation Commission, NOVEC could, subject to applicable law, seek to securitize the costs \nof its RBP collateral requirement (in the form of low-interest, ratepayer-backed bonds sold to investors) and \nthen recover such costs through a Virginia State Corporation Commission-approved non-bypassable charge.   \n275 Int’l Swaps & Derivatives Ass’n, 2016 ISDA Credit Support Annex (Bilateral Form; New York Law) \n¶ 6(c) (“Use of Posted Collateral.  Unless otherwise specified in Paragraph 13 and without limiting the rights \nand obligations of the parties under Paragraphs 3, 4(d)(ii), 5, 6(d) and 8, if the Secured Party is not a \nDefaulting Party or an Affected Party with respect to a Specified Condition and no Early Termination Date \nhas occurred or been designated as the result of an Event of Default or Specified Condition with respect to \nthe Secured Party, then the Secured Party will, notwithstanding Section 9-207 of the New York Uniform \nCommercial Code, have the right to (i) sell, pledge, rehypothecate, assign, invest, use, commingle or \notherwise dispose of, or otherwise use in its business any Posted Collateral it holds, free from any claim or \nright of any nature whatsoever of the Pledgor, including any equity or right of redemption by the Pledgor.”)."},{"page":91,"startToken":30211,"endToken":30576,"text":"91 \nlevel of collateral to cover the utility’s exposure if the data center does not perform as \ncontemplated—which is the same logic underlying PJM’s credit requirement. \nFor example, Ohio Power Company (operating as AEP Ohio) Schedule DCT (Data \nCenter Tariff) requires that data centers that do not meet certain creditworthiness standards \nmust provide collateral at contract signing equal to 50% of their total minimum charges for \nthe full contract term.276  AEP Ohio also requires the customer to reimburse 100% of \nbuildout costs if it cancels or delays a project by more than 12 months before the target \nenergization date.  These are the types of costs that would be contemplated when deriving \na credit requirement. \nFor Dominion, the Virginia State Corporation Commission approved a new Rate \nSchedule GS-5, effective January 1, 2027, for loads 25 MW or greater and a load factor of \nat least 75%.  Rate Schedule GS-5 requires such loads to contract with Dominion for at \nleast 14 years and allow for early termination exit fees covering any outstanding minimum \ncharges over the remaining contract duration.  With respect to collateral requirements, the \nVirginia State Corporation Commission approved Dominion’s proposed terms, “including: \n(1) $1.5 million/MW; (2) a reduction up to 70% based on the customer’s established credit; \n(3) provisions for third-party guarantees and letters of credit; and (4) releasing 1/14th of \nthe collateral requirement each year throughout the contract.”277  As Dominion has \ndescribed, the collateral must be provided before the large load is energized.278  \n \n276 See Ohio Power Company, P.U.C.O. No. 21, Schedule DCT, Original Sheet No. 223-5. \n277 Application of Virginia Electric and Power Company, For a 2025 biennial review of the rates, terms, and \nconditions for the provision of generation, distribution and transmission services pursuant to § 56-585.1 A \nof the Code of Virginia, Case No. PUR-2025-00058, Final Order, at 25 (Va. S.C.C. Nov. 25, 2025), \nhttps://www.scc.virginia.gov/docketsearch/DOCS/89g601!.PDF. \n278 Meeting the Demands for Large-Load Customers with Reliable, Affordable, and Increasingly Clean \nEnergy, \nDominion \nEnergy, \n5 \n(May \n2026), \nhttps://sustainability.dominionenergy.com/GS-\n5%20Large%20Load%20Rate%20Class%20Report.pdf \n[https://perma.cc/3RZD-C3M4] \n(“Collateral"},{"page":92,"startToken":30576,"endToken":30914,"text":"92 \nSimilarly, the Pennsylvania Public Utility Commission has approved PPL’s Rate \nSchedule LP-6 for large loads (50 MW or greater) that commenced service on or after \nOctober 1, 2025.279  PPL’s Rate Schedule LP-6 calls for a minimum contract term of 10 \nyears and “security in an amount equal to the cost of upgrades needed to serve the customer, \nincluding, but not limited to, the costs that the Company would not have incurred but for \nthe interconnection of the customer.”280  Rate Schedule LP-6 provides that in the event the \nlarge load defaults PPL “shall draw on the security instrument in the amount of the \noutstanding revenue guarantee.”281 \nAs can be seen, LSEs are imposing collateral requirements needed to cover the \ncosts to serve the large loads—again, similar to PJM’s LSE RBP credit requirement to \ncover the costs of the capacity needed to serve these new large loads. \n6. \nWhile PJM has proposed a just and reasonable LSE credit \nrequirement and urges Commission acceptance of it, PJM \nrecognizes that there is time to investigate further and consents to \nmodification if the Commission desires. \nPJM has proposed a just and reasonable approach to determining the proper \nbuyer-side LSE RBP credit requirement.  Nonetheless, PJM understands that reasonable \nminds may differ as to how to set the initial RPM Credit Rate.  Some have suggested that \nthe credit rate should be keyed to the actual MW-weighted average of the levelized \nprocurement cost of all selected RBP Sell Offers that results from the RBP and not the \n \nrequirements, which were approved to become more stringent pursuant to a recent Commission ruling, are \ndue to be paid before the customer’s meter is set and its project is energized.”). \n279 PPL Electric Utilities Corporation Rate Schedule LP-6 Large Load Interconnections, Supplement No. 2 \nto Electric Pa. P.U.C. No. 202, First Revised Page No. 35C (effective July 1, 2026), \nhttps://www.pplelectric.com/site/-/media/PPLElectric/At-Your-Service/Docs/Current-Electric-\nTariff/2026/July/Rate-Schedule-LP-6-Large-Load-Interconnections.pdf (“PPL Rate Schedule LP-6”). \n280 Id.   \n281 Id."},{"page":93,"startToken":30914,"endToken":31301,"text":"93 \nmaximum of such value.282  PJM consents to such an approach, because it maintains a \ncredit requirement corresponding to the level of risk necessary to insulate other \nratepayers283 and would implement such a change on compliance if the Commission \ndirects.284   \nFurther, although PJM has proposed a just and reasonable approach to determining \nthe proper buyer-side LSE RBP credit requirement, PJM recognizes that reasonable minds \nmay differ on the credit approach.  Given that an LSE’s collateral is not required to be \nposted until the first Delivery Year for which RBP Resources will be in service and \nproviding capacity, i.e., the 2028/2029 Delivery Year,285 the LSE credit rules do not need \nto be effective for the RBP to be conducted.  To be clear, the RBP Seller credit rules in \nproposed Tariff, Attachment DD, section 18.8(a) do need to be effective to conduct the \nRBP.  Accordingly, consistent with the consent PJM provided in the July 31 Filing to the \nCommission’s exercise of authority to modify and/or sever the proposed Tariff and RAA \nlanguage, as needed and permitted under the FPA and NRG Power Marketing,286 PJM \nwould consent to the Commission resolving the applicable buyer-side LSE RBP Credit \nRate through additional procedures.   \n \n282 See NOVEC Protest at 22. \n283 See July 31 Filing, Transmittal Letter at 3-4, 130-33. \n284 For this reason, PJM does not consent to the rolling forward exposure-based credit requirement suggested \nby Equinix Inc.  See Equinix Comments at 16. \n285 See July 31 Filing, proposed Tariff, Attachment DD, section 18.8(b). \n286 NRG Power Mktg., LLC, 862 F.3d 108 (D.C. Cir. 2017).  As the Commission has repeatedly stated, “[t]he \nUnited States Court of Appeals for the District of Columbia Circuit has held that, in certain circumstances, \nthe Commission has ‘authority to propose modifications to a utility’s [FPA section 205] proposal if the utility \nconsents to the modifications.’”  N.Y. Indep. Sys. Operator, 188 FERC ¶ 61,051, at P 22 n.36 (2024) (second \nalteration in original) (citing NRG Power Mktg., 862 F.3d at 114-15); see Midcontinent Indep. Sys. Operator, \nInc., 180 FERC ¶ 61,141, at P 26 n.29 (2022) (same), order on reh’g, 182 FERC ¶ 61,096 (2023); ISO New \nEng., Inc., 175 FERC ¶ 61,172, at P 16 n.20 (2021) (same)."},{"page":94,"startToken":31301,"endToken":31552,"text":"94 \nK. \nThe Proposed Transmission Owner Exit Requirements Are Necessary to \nEnsure Price Certainty for RBP Resources Over the 15-year Commitment \nPeriod, Thereby Encouraging Participation in the RBP. \nIn the event that a Transmission Owner elects to exit PJM during or prior to the \n2042/2043 Delivery Year, PJM proposed Tariff provisions in Attachment DD, section 18.7 \nplaces such a Transmission Owner on notice of their responsibility to avoid undermining \nthe cost certainty of the 15-year RBP Resource commitment, which aids the financing of \nRBP Resources that can be placed in service quickly, as it would avoid creating stranded \ncosts related to RBP Resources and the loads served by such resources as a result of a \nTransmission Owner’s decision to leave PJM.   \nAt bottom, the proposed Tariff provisions balance the dual interests of providing \nadequate notice to Transmission Owners and retaining flexibility in recognition that, \nshould a Transmission Owner elect to exit PJM at some point in the future.  Furthermore, \nthe proposed Tariff provisions help to protect residential customers and other consumers \nremaining in the PJM Region from being held responsible for stranded RBP costs arising \nfrom a Transmission Owners’ decision to leave PJM, in keeping with the Ratepayer \nProtection Pledge, which a significant number of PJM’s Transmission Owners are \nsignatories to.287 \n \n287 The PJM Transmission Owners that are signatories to the Ratepayer Protection Pledge and have filed \ncomments and protests in this docket include: AES Corporation, EKPC, Dominion, FirstEnergy, and PPL.  \nSee White House Ratepayer Protection Pledge Signatories."},{"page":95,"startToken":31552,"endToken":31877,"text":"95 \n1. \nThe proposed Tariff language is sufficiently clear to put \nTransmission Owners on notice of their responsibilities with respect \nto RBP Resources in the event that they choose to exit from PJM.   \nSeveral intervenors raise concerns that the proposed Tariff language implementing \nthe Transmission Owner exit process lacks sufficient clarity and specificity.288  AEP claims \nthat (1) the “standard” applied to the agreement into which Transmission Owners and RBP \nResources in the zone may enter into in proposed Tariff, Attachment DD, section 18.7(a) \nis unclear; (2) PJM has not explained how it may “elect” to retain RBP Resources that can \nbe pseudo-tied into PJM; and (3) it is unclear what sort of contractual arrangement in \nproposed Tariff, Attachment DD, section 18.7(b) a Transmission Owner should enter into \nwith RBP Resources outside of the zone.289  PPL asserts that PJM’s proposed language \nviolates the FPA’s requirement to provide clear and specific rates and charges, particularly \nwith respect to the costs that would be at issue if a resource is pseudo-tied or in the event \nof a Transmission Owner’s exit, as well as with respect to who would be responsible for \nmaking a filing with the Commission.290  Similarly, AEP argues that exit terms should be \nable to be determined prior to a Transmission Owner withdrawing from PJM.291   \nNone of these arguments render PJM’s proposed Tariff revisions unjust and \nunreasonable.  As discussed below, there is sufficient detail provided in these revisions to \nput Transmission Owners on notice of their responsibilities in a manner that also provides \nfor flexibility to meet those obligations, particularly in light of the complexity and \nunknowns involved in a future, hypothetical withdrawal.   \n \n288 See, e.g., AEP Limited Protest at 12-13; PPL Limited Protest and Request for Clarification at 10-12; EKPC \nLimited Answer at 5-6.   \n289 AEP Limited Protest at 12-13. \n290 PPL Limited  Protest and Request for Clarification at 10-12. \n291 AEP Limited Protest at 17-20."},{"page":96,"startToken":31877,"endToken":32218,"text":"96 \nImportantly, in the event a Transmission Owner does exit, there will be extensive \nnegotiations that take place, not only with respect to RBP, but also a variety of other \nobligations.  Therefore, PJM drafted these sections with the intent of providing flexibility \nto the Transmission Owner and RBP Resource to develop the specific “rates, terms, and \nconditions” to effectuate the obligation to “preserve RBP commitments.”   \nCritically, however, this flexibility is counterbalanced against the detailed Tariff \nprovisions set forth in proposed Tariff, Attachment DD, section 18, which specifies the \nnecessary terms and conditions for implementing the RBP.  Regarding AEP’s arguments \nabout entering into agreements with RBP Resources, the proposed Tariff language in \nAttachment DD, sections 18.7(a) and 18.7(b) is sufficiently clear, particularly when read \nin the context of all of the proposed Tariff language.  In both proposed sections, it is clear \nthat the purpose of such agreements is to ensure that both the exiting Transmission Owner \n“preserves the RBP commitments with the owners of”292 RBP Resources.  This, of course, \nis the entire purpose of this filing—to ensure that PJM has sufficient resources to maintain \nreliability throughout the 15-year commitment period.   \nWhen reviewing proposed tariff language, the Commission must interpret tariff \nprovisions “as part of an integrated whole.”293  Applying this principle here necessarily \nleads to the conclusion that such “rates, terms, and conditions” might include the issues \naddressed in proposed Tariff, Attachment DD, section 18 that would “preserve RBP \n \n292 July 31 Filing, proposed Tariff, Attachment DD, section 18.7(a) (emphasis added). \n293 Derby Fuel Cell, LLC, 194 FERC ¶  61,147, at P 22 & n.46 (2026) (citing Columbia Gas Transmission \nCorp., 27 FERC ¶ 61,089, at 61,166 (1984) (“In construing what a tariff means, certain general principles \napply.  One looks first to the four corners of the entire tariff, considers the entire instrument as a whole, \ngiving effect so far as possible to every word, clause and sentence, and attributes to the words used the \nmeaning which is generally used, understood, and accepted.”))."},{"page":97,"startToken":32218,"endToken":32525,"text":"97 \ncommitments.”  At the same time, as discussed above, PJM intends to preserve flexibility \nfor exiting Transmission Owners and RBP Resources as they negotiate any agreement. \nWith respect to concerns that PJM may “elect” to retain an RBP Resource as a \nCapacity Resource, PJM notes that it must retain the discretion necessary to ensure how \nbest to meet PJM’s resource adequacy and reliability needs—e.g., whether it makes sense \nfor PJM to keep that RBP Resource after considering the topology of the transmission \nsystem at the time of the desired exit.  As Ms. Croop discusses in her affidavit, submitted \nwith the July 31 Filing, for example, PJM does not project and calculate certain parameters \n15 years out.294  Further, PJM’s ongoing RTEP transmission planning processes will \ncontinue to assess the transmission system at any given time to account for changes to \nensure ongoing deliverability of capacity resources.295  For example, it may be the case \nthat, at the time the decision to exit has been made, PJM no longer needs that particular \nRBP Resource to be retained to meet reliability needs.  This discretion is also part and \nparcel of ensuring just and reasonable rates, as discussed in the NEDC/PJM Governors’ \nPrinciples which state, among other things, that PJM should “prevent consumers from \nbearing excessive ongoing costs.”296 \nWith respect to PPL’s arguments regarding pseudo-tie costs,297 PJM’s proposed \nTariff language is more than sufficiently specific and clear regarding the costs at issue.  \nProposed Tariff, Attachment DD, section 18.7(a) states that the costs to be paid by the \nexiting Transmission Owner would include those needed to ensure “that such resource \n \n294 July 31 Filing, Croop Aff. ¶ 8. \n295 Id. ¶ 9. \n296 NEDC/PJM Governors’ Principles at 1; see 2026 PJM CIFP Proposal at 1. \n297 PPL Limited Protest and Request for Clarification at 11."},{"page":98,"startToken":32525,"endToken":32802,"text":"98 \nmeets the external Capacity Resource eligibility requirements set forth in Tariff, \nAttachment DD, section 5.5A prior to the Transmission Owner exiting PJM \nInterconnection, L.L.C.”  Again, the overall intent of this proposal is to ensure that PJM \nhas sufficient capacity to meet reliability needs.  Should a Transmission Owner decide, in \nthe future, to exit PJM, and if that Transmission Owner has incurred RBP responsibilities, \nthat Transmission Owner must ensure that it continues to satisfy those responsibilities.  One \noption that the Transmission Owner may choose is to have the RBP Resource pseudo-tie \nback into PJM in the event the exiting Transmission Owner leaves with an RBP Resource.  \nIf such RBP Resource will be pseudo-tied, PJM’s proposed Tariff language and existing \nlanguage in Attachment DD are clear as to what that would entail. \nWith respect to arguments concerning the requisite Commission filing and costs \nassociated with a Transmission Owner exiting PJM with net load, PJM again notes that \nsuch costs are appropriately decided at the time of Transmission Owner’s exit and subject \nto Commission approval.  It is impossible to determine, at this point in time, what exactly \nthose circumstances may be.  The proposed Tariff language simply puts parties on notice \nthat final cost determinations will be approved by the Commission.   \nSimilarly, the proposed Tariff provisions do not specify who may make such filing, \nas, again, it is impossible to determine, at this time, the scope of any Transmission Owner’s \nexit proceeding that may take place.  The proposed Tariff provides appropriate flexibility \nin this regard while also providing sufficient notice of the nature of the costs, namely those \nassociated with ensuring RBP Resources commitments are appropriately honored."},{"page":99,"startToken":32802,"endToken":33156,"text":"99 \nAEP and EKPC argue that exit terms should be specified up front and consistent \nwith cost causation, adding that the lack of locational requirements298 underpins the \nuncertainty as to cost responsibility.299  For the reasons discussed above in this subsection, \nPJM’s proposed Tariff revisions are just and reasonable because, among other things, they \nspecifically set out the obligations associated with RBP Resources, so there can be no \nquestion as to the types of responsibilities an exiting Transmission Owner may need to \nconsider prior to exiting PJM.   \nFurther, AEP’s arguments fail to appreciate the numerous options provided to an \nexiting Transmission Owner regarding how it may choose to honor its RBP responsibilities, \nwhich greatly mitigates against the argued uncertainty.  For example, a Transmission \nOwner exiting with committed RBP Resources in its zone may (1) negotiate an agreement \nwith the RBP Resource owners, free to advocate for whatever costs they deem appropriate \nto preserve the RBP Resource commitments; (2) attempt to pseudo-tie the RBP Resource \ninto PJM, paying associated costs consistent with proposed Tariff, Attachment DD, \nsection 18.7(a); or (3) pay for the costs associated with the remainder of the RBP \nResource’s term as approved by the Commission.300  If a Transmission Owner exits with \nnet load, it has similar options: (1) negotiate an agreement with the RBP Resources; or \n(2) pay all forward obligations as approved by the Commission.301  In short, the proposed \nTariff, when read as a whole, provides sufficient notice regarding the nature of \n \n298 Responses to locational arguments are set forth in this Answer, see supra Part I.C.3. \n299 AEP Limited Protest at 17-18; EKPC Limited Answer at 4. Similar arguments regarding certainty \nnecessary for Transmission Owners to make informed decisions about whether to exit PJM, and whether \nalleged uncertainty constrains such future decision-making, are raised by PPL and FirstEnergy and are \naddressed by the responses provided in this section.  See PPL Limited  Protest and Request for Clarification \nat 9-10; FirstEnergy Comments and Protest at 5. \n300 See July 31 Filing, proposed Tariff, Attachment DD, section 18.7(a).   \n301 See id., section 18.7(b)."},{"page":100,"startToken":33156,"endToken":33428,"text":"100 \nresponsibilities and the flexibility to meet them based on their own informed business \ndecision-making. \n2. \nThe proposed Tariff language in section 18.7(b) requiring an exiting \nTransmission Owner to pay “all forward obligations” is needed to \nensure that RBP Resources have financial certainty and that loads \nremaining in PJM are not forced to bear excessive costs. \nAEP asserts that PJM’s proposed Transmission Owner exit provisions pertaining \nto net load exiting PJM in section 18.7(b) are unjust and unreasonable because they do not \nappear to incorporate the effect of offsetting credits that load remaining in PJM will benefit \nfrom.302  Similarly, AEP further argues that exiting Transmission Owners may be forced \nto bear excessive costs should RPM clearing levels decline as a result of its exiting load—\nload remaining in PJM would see the benefit of this through RBP credits, while the exiting \nload would continue to pay for “surplus” capacity.303   \nBut, as PJM has explained, an exiting Transmission Owner will have opportunities \nto seek further cost recovery as needed.  The provisions put Transmission Owners on notice \nof the RBP-related commitments that must be honored in order to maintain reliability in \nPJM, which should be among a Transmission Owner’s considerations when weighing the \ncosts and benefits of exiting.   \nProposed Tariff, Attachment DD, section 18.7(b) provides two avenues through \nwhich an exiting Transmission Owner may honor its responsibilities.  First, it may enter \ninto an agreement with the appropriate RBP Resource(s) to negotiate “appropriate rates, \nterms, and conditions” necessary to preserve its RBP commitments.  This option would \n \n302 AEP Limited Protest at 13-15. \n303 Id. at 15-17."},{"page":101,"startToken":33428,"endToken":33740,"text":"101 \npermit the Transmission Owner to develop cost recovery provisions that it believes are \nappropriate for preserving the ability of the RBP Resource(s) to continue operating in PJM.   \nOnly if an exiting Transmission Owner opts not to enter into an agreement (or does \nnot reach agreement with the RBP Resource(s)) that the next option becomes available.  \nThis second option, then, requires the exiting Transmission Owner to pay “all forward \nobligations on an accelerated basis.”  As discussed in the July 31 Filing, such cost recovery \nis necessary to ensure that the load remaining in PJM is not forced to bear the costs of \nincreased RBP charges resulting from a unilateral business decision made by the exiting \nTransmission Owner.304   \nEven here, there are two additional opportunities for the exiting Transmission \nOwner to advocate for further cost recovery.  First, proposed Tariff, Attachment DD, \nsection 18.7(b) makes clear that the costs of “all forward obligations” will be subject to \nCommission review, meaning that the exiting Transmission Owner would have the \nopportunity to dispute any allocated costs either before the filing or once it is filed.  Second, \nas PJM explained in the July 31 Filing:  \nWhile the exiting Transmission Owner would be initially \nresponsible to pay for the costs necessary to ensure no RBP \nResource becomes a stranded asset, nothing in PJM’s proposal \nwould preclude such a Transmission Owner from seeking to recover \nany such costs from the relevant large loads.305   \nTherefore, the exiting Transmission Owner is in no way prevented from seeking further \ncost recovery from load remaining in PJM, should it believe further payment is warranted. \nAEP asserts that load outside of PJM is “similarly situated load that stays in PJM,” \ninsofar as load remaining in PJM may benefit from offsets, while load outside of PJM will \n \n304 July 31 Filing, Transmittal Letter at 94-95. \n305 Id. at 95."},{"page":102,"startToken":33740,"endToken":34198,"text":"102 \nbe required to pay more.306  Contrary to such an assertion, load that leaves PJM with an \nexiting Transmission Owner would no longer be obligated under the PJM Tariff to pay any \napplicable RBP Charges while load that remains in PJM would be bound by the Tariff and \nrequired to pay applicable RBP Charges.  This distinction is material to the “similarly \nsituated” inquiry,307 as it demonstrates that it is indeed just and reasonable to treat these \ntwo differently situated loads differently.  This is also consistent with how the Commission \nhas previously examined whether two different loads were similarly situated.308 \n3. \nThe proposed Tariff language is consistent with Commission \nprecedent regarding RTO withdrawal and does not change any \nexisting exit processes or commitments. \nAEP’s protest includes an extensive background on the “current terms” for \nwithdrawing from PJM and calls into question whether the responsibilities set forth in \nproposed Tariff, Attachment DD, section 18.7 would alter existing non-RBP \nresponsibilities for Transmission Owners that seek to exit PJM.309  To be clear, as discussed \n \n306 AEP Limited Protest at 14-15. \n307 See N.Y. Indep. Sys. Operator, Inc., 162 FERC ¶ 61,124, at P 10 (2018) (“To say that entities are similarly \nsituated does not mean that there are no differences between them; rather, it means that there are no \ndifferences that are material to the inquiry at hand.” (citing Fla. v. Long, 108 S. Ct. 2354, 2358 (1998); City \nof Los Angeles v. Lyons, 103 S. Ct. 1660, 1663 (1983))). \n308 See, e.g., Am. Elec. Power Serv. Corp. v. Midcontinent Indep. Sys. Operator, Inc., 168 FERC ¶ 61,176, at \nP 32 (2019) (“We also find that it is not unduly discriminatory for [Midcontinent Independent System \nOperator, Inc. (“MISO”)] to impose non-market-to-market congestion charges on loads pseudo-tied out of \nMISO into SPP (e.g., the Minden load) but not impose those charges for load physically located within SPP.  \nThe Minden load is not similarly situated to load located outside of MISO’s footprint, because Minden’s load \nis physically located in MISO and, thus, AEP imposes congestion costs on the MISO transmission system \nwhen it serves this load.” (footnote omitted)); City of Alameda v. Pac. Gas & Elec. Co., 176 FERC ¶ 61,013, \nat P 70 (“In this case, we find that Alameda’s load and PG&E’s retail load are not similarly situated.  Due to \nthe configuration of Alameda’s and PG&E’s systems, PG&E customers on the Oakland-C system cannot be \nfed from anywhere else except from the Oakland-C bus during an N-1 contingency, whereas Alameda is able \nto transfer its load to be fed from the Oakland-J bus.”), order addressing arguments raised on reh’g & \nproviding clarification, 177 FERC ¶ 61,038 (2021). \n309 AEP Limited Protest at 20-27."},{"page":103,"startToken":34198,"endToken":34540,"text":"103 \nfurther, below, the proposed Tariff language does not, and is not intended to, alter any of \nthese existing responsibilities.   \nAEP relies heavily on the Duquesne proceedings, in which Duquesne Light \nCompany (“Duquesne”) sought to exit PJM and join MISO, but ultimately “rejoined” \nPJM.310  The Commission’s discussion and analysis in the Duquesne proceedings provide \nsome of the foundational principles governing withdrawal from RTOs/ISOs.  While PJM \ndoes not take issue with these Duquesne principles reiterated by AEP, the Commission \nshould recognize that the exit provisions proposed in the instant filing are entirely \nconsistent with them.  First, RBP commitments are established at the time of the RBP and \nare set for 15 years.311  Therefore, a Transmission Owner exiting PJM during this 15-year \ncommitment period would be obligated to honor its capacity responsibilities for this period.   \nIn Duquesne II, as AEP explains, the Commission found that Duquesne would be \nresponsible for costs that are “fixed” at the time the costs are assigned, but it would not be \nresponsible for costs that are “not fixed” and are instead reallocated on an annual basis.312 \nRegarding capacity costs specifically, AEP cites to both the RAA and Duquesne I for the \nproposition that an exiting LSE is responsible for capacity costs through the end of the \nDelivery Year during which it provided notice of withdrawal, and if it provided notice after \nthe auction parameters were posted, the exiting LSE would be responsible for costs of that \nDelivery Year.313   \n \n310 Duquesne Light Co., 122 FERC ¶ 61,039 (2008) (“Duquesne I”); Midwest Indep. Transmission Sys. \nOperator, Inc., 124 FERC ¶ 61,219 (2008) (“Duquesne II”) (collectively, “Duquesne”). \n311 See July 31 Filing, proposed Tariff, Attachment DD, section 18.4 (“The Reliability Backstop Procurement \nshall offer commitments for RBP UCAP MW for a fixed period of fifteen (15) Delivery Years . . . .”). \n312 AEP Limited Protest at 22-23 (citing Duquesne II at P 168). \n313 Id. at 25-26 (citing RAA, sections 5.1.1-5.1.3(a), 7.2, 7.2A, 11.1-11.3; Duquesne I at PP 83, 93)."},{"page":104,"startToken":34540,"endToken":34824,"text":"104 \nNone of these holdings undermine PJM’s proposed treatment of RBP commitments \nin the event of a Transmission Owner exiting PJM.  Namely, while the exact costs may not \nbe known given that settlements will account for RPM Auction outcomes under a contract \nfor difference settlement structure, all of the pertinent information necessary to calculate \nthe charges for an RBP Resource selected through the RBP will be known and fixed for a \n15-Delivery Year term.  This is appropriate given the unique nature of the RBP, which is \na one-time effort to ensure reliability throughout PJM in a predictable and efficient manner.   \nIn Duquesne II, the Commission emphasized that its decision regarding capacity \nobligations was rooted in the fact that capacity was procured for Duquesne.  For example, \nthe Commission found that Duquesne was “liable for the costs incurred in the prior auctions \nbecause the auctions were conducted while Duquesne was a member, [and] the auction \nobtained capacity based on Duquesne’s load in order to ensure the reliability of the \nDuquesne zone.”314  Capacity costs are unlike high voltage transmission projects, the \nCommission continued, because they “were not undertaken specifically to support \nDuquesne’s load or the reliability of that load, but would have occurred regardless of \nwhether Duquesne was a member of PJM.”315  Critically, the Commission also appreciated  \nthat Duquesne should not be able to escape responsibility for capacity committed on its \nbehalf:   \nIn this case, Duquesne understood that PJM was procuring capacity \non its behalf and therefore should be obligated to pay for that \ncapacity.  Indeed, allowing Duquesne to escape its obligations to pay \nfor the capacity acquired on its behalf will force PJM to collect the \n \n314 Duquesne II at P 169. \n315 Id."},{"page":105,"startToken":34824,"endToken":35117,"text":"105 \namount it is obligated to pay the generators from the remaining \nparticipants in PJM, hardly a just and reasonable result.316   \nThe Commission even contemplated how PJM could mitigate capacity costs for Duquesne, \nincluding by “negotiat[ing] to ensure that Duquesne will be able to use the capacity it has \nacquired to meet its reliability obligations when it withdraws from PJM,”317 and this is in \nkeeping with the spirit of PJM’s proposed Tariff revisions which provide flexibility for \nnegotiated bilateral agreements, pseudo-ties, and flat payment for RBP costs subject to \nCommission approval. \nIn sum, the exit provisions proposed by PJM in the instant proceeding are consistent \nwith Commission precedent, particularly in light of the urgency with which PJM must \nacquire and maintain capacity in this one-time procurement. \n4. \nThe proposed Tariff language on exit responsibilities is properly \nlocated in the Tariff and the RAA. \nSeveral intervenors filed comments contending that the inclusion of these proposed \nexit responsibility Tariff provisions violated the CTOA and/or should have been included \nin the CTOA rather than the Tariff and RAA.318  To the contrary, as discussed below, these \nprovisions are not required to be in the CTOA, as they are not and do not relate to or affect \ntransmission-related costs. \nThe July 31 Filing makes clear that if a Transmission Owner makes the business \ndecision to exit PJM, “the treatment of RBP Resources and load that has been allocated \nRBP Charges is, at bottom, a matter of close-out or settlement consequences of the RBP \nand thus properly addressed in [proposed] Tariff, Attachment DD [section 18].  The \n \n316 Duquesne I at P 89 (footnote omitted). \n317 Id. PP 95-97. \n318 Indicated TOs Protest at 2, 4-8; PPL Limited Protest and Request for Clarification at 3-7."},{"page":106,"startToken":35117,"endToken":35435,"text":"106 \ndeparting RBP Resource’s UCAP MW and/or the departing load’s proportional share of \nthe remaining term [contract for difference] are both incident to the RBP framework.”319  \nNone of the arguments against inclusion of these provisions in proposed Tariff, \nAttachment DD, section 18, respond to this characterization.  Further, and tellingly, none \nargue that the initial cost allocations proposed in Tariff, Attachment DD, section 18.3 are \nrelated transmission costs.  If they are not transmission costs when they are being allocated, \nthe mere fact that an exiting Transmission Owner will bear initial responsibility for \nhonoring RBP Resource commitments does not make them so.  Thus, it is appropriate for \nan exiting Transmission Owner, who has made the business decision to leave PJM, to take \nresponsibility for commitments that it has advance notice of through these proposed Tariff \nprovisions.  The proposed exit provisions are located in proposed Tariff, Attachment DD, \nsection 18.7, and the Tariff is applicable to all entities participating in PJM.320   \n5. \nThe proposed Tariff revisions do not violate the separation of \nfunctions requirements of the Commission. \nPPL asserts that the proposed Tariff revisions violate the Commission’s Standards \nof Conduct contained in 18 C.F.R. part 358 regarding separation of functions “whereby the \ntransmission function employees of a transmission-owning public utility must operate \nindependently of the marketing function employees.”321  But PJM is not proposing to \npermit “the sale for resale in interstate commerce, or the submission of offers to sell in \ninterstate commerce, of electric energy or capacity.”322  Rather, the proposed requirements \n \n319 July 31 Filing, Transmittal Letter at 96. \n320 This addresses concerns raised by PPL that since not all LSEs have executed the RAA, they may not be \nsubject to the exit requirements.  PPL Limited  Protest and Request for Clarification at 8-9. \n321 PPL Limited Protest and Request for Clarification at 7-8. \n322 18 C.F.R. § 358.3(c)(1)."},{"page":107,"startToken":35435,"endToken":35690,"text":"107 \nare merely intended to honor obligations that would have pre-existed the exit of a \nTransmission Owner from PJM.  Furthermore, in practice, the separation of functions \nprinciples have been applied in the context of  affiliate transactions involving common use \nof marketing-related employees.323  In any event, if a Transmission Owner exiting PJM \nwere to have concerns about potential violations under 18 C.F.R. part 358, PJM notes that \nactivity that may otherwise violate separation of functions is permissible, pursuant to 18 \nC.F.R. § 358.2(d) and 18 C.F.R. § 358.1(d), respectively, where ordered by the \nCommission or where the Commission has granted waiver of such requirements. \nII. \nCONCLUSION \nPJM asks that the Commission consider this Answer and accept the proposed Tariff \nrevisions in this docket, effective September 29, 2026, as requested. \n \n \n \n \n \n \n \nRespectfully submitted, \n \n/s/ Vivian W. Chum   \n     \nCraig Glazer \nVice President – Federal Government Policy \nPJM Interconnection, L.L.C. \n1200 G Street, NW, Suite 600 \nWashington, D.C.  20005 \n(202) 423-4743 \ncraig.glazer@pjm.com \n \nChenchao Lu \nAssociate General Counsel \nPJM Interconnection, L.L.C. \n2750 Monroe Boulevard \nAudubon, PA  19403 \n(610) 666-2255 \nchenchao.lu@pjm.com \nRyan J. Collins \nVivian W. Chum \nAnne Marie Hirschberger \nWright & Talisman, P.C. \n1200 G Street, NW, Suite 600 \nWashington, D.C.  20005 \n(202) 393-1200 \ncollins@wrightlaw.com \nchum@wrightlaw.com \nhirschberger@wrightlaw.com \nOn Behalf of \nPJM Interconnection, L.L.C. \nSeptember 10, 2026 \n \n \n \n \n \n \n323 See, e.g., Buckeye Plains Solar Project, LLC, 189 FERC ¶ 61,101, at P 20 (2024)."},{"page":108,"startToken":35690,"endToken":35764,"text":"CERTIFICATE OF SERVICE \n \nI hereby certify that I have this day served the foregoing document upon each \nperson designated on the official service list compiled by the Secretary in this proceeding. \n \nDated at Washington, D.C., this 10th day of September 2026. \n \n \n \n \n \n \n \n \n /s/ Vivian W. Chum  \nVivian W. Chum \nWright & Talisman, P.C. \n1200 G Street, NW, Suite 600 \nWashington, DC  20005 \nchum@wrightlaw.com \n(202) 393-1200 \n \n \nAttorney for \nPJM Interconnection, L.L.C."},{"page":109,"startToken":35764,"endToken":35779,"text":"Appendix A \n \nProtests, Comments, Requests for Clarification, and Answers Filed to Date  \nDocket No. ER26-3380-000"},{"page":110,"startToken":35779,"endToken":36039,"text":"i \nAppendix A \nProtests, Comments, Requests for Clarification, and Answers Filed to Date  \nDocket No. ER26-3380-000 \n• Comments of Advanced Energy United (Aug. 21, 2026) (“AEU Comments”) \n• Motion to Intervene and Initial Comments of Amazon Energy LLC (Aug. 21, 2026) \n(“Amazon Comments”) \n• Limited Protest of American Electric Power Service Corporation (Aug. 21, 2026) \n(“AEP Limited Protest”) \n• Comments of American Municipal Power, Inc. (Aug. 21, 2026) (“AMP \nComments”) \n• Motion for Leave to Answer, and Answer, of the Attorney General of the \nCommonwealth of Kentucky (Sept. 2, 2026) (“Kentucky Attorney General \nAnswer”) \n• Motion to Intervene and Comments of Base Power Inc. (Aug. 21, 2026) (“Base \nPower Comments”) \n• Comments of Blue Ridge Power Agency (Aug. 21, 2026) (“Blue Ridge \nComments”) \n• Request for Clarification of Calibrant Energy (Aug. 21, 2026) (“Calibrant Request \nfor Clarification”) \n• Limited Protest of Constellation Energy Generation, LLC (Aug. 21, 2026) \n(“Constellation Limited Protest”) \n• Motion for Leave to Answer and Answer of Constellation Energy Generation, LLC \n(Sept. 8, 2026) (“Constellation Answer”) \n• Motion to Intervene and Comments of CPV Power Holdings, LP (Aug. 21, 2026) \n(“CPV Comments”) \n• Comments of the Data Center Coalition (Aug. 21, 2026) (“DCC Comments”) \n• Partial Protest and Comments of Dominion Energy Services, Inc. (Aug. 21, 2026) \n(“Dominion Partial Protest and Comments”) \n• Protest of East Kentucky Power Cooperative (Aug. 21, 2026) (“EKPC Protest”) \n• Motion for Leave to File Limited Answer and Limited Answer of East Kentucky \nPower Cooperative (Sept. 4, 2026) (“EKPC Limited Answer”) \n• Comments and Protest of E-Cubed Policy Associates, L.L.C. and Motion for Leave \nto File One Day Out of Time (Aug. 22, 2026) (“E-Cubed Protest”)"},{"page":111,"startToken":36039,"endToken":36337,"text":"ii \n• Comments of Equinix Inc. on the PJM Interconnection, L.L.C. Filing Regarding Its \nReliability Backstop Procurement to Address Reliability Adequacy Concerns \nStemming from Large Loads (Aug. 21, 2026) (“Equinix Comments”) \n• Comments and Protest of FirstEnergy Service Company (Aug. 21, 2026) \n(“FirstEnergy Comments and Protest”) \n• Comments of Google LLC (Aug. 21, 2026) (“Google Comments”) \n• Comments of the Organization of PJM States, Inc. (Aug. 21, 2026) (“OPSI \nComments”) \n• Illinois Commerce Commission Comments (Aug. 19, 2026) (“ICC Comments”) \n• Protest of the Independent Market Monitor for PJM (Aug. 21, 2026) (“IMM \nProtest”) \n• Protest of the Indicated PJM Transmission Owners (Aug. 21, 2026) (“Indicated \nTOs Protest”) \n• Comments of the Institute for Policy Integrity at New York University School of \nLaw on PJM Interconnection, L.L.C. Section 205 Filing to Implement Reliability \nBackstop Procurement (Aug. 21, 2026) (“NYU Institute Comments”) \n• Protest, Motion to Reject, and Alternative Request for the Imposition of Conditions \nof Joint Consumer Advocates (Aug. 21, 2026) (“JCA Protest”) \n• Limited Protest of the NRG Companies (Aug. 21, 2026) (“NRG Limited Protest”) \n• Comments of the New Jersey Board of Public Utilities (Aug. 21, 2026) (“NJ BPU \nComments”) \n• Motion to Intervene and Protest of Nicholas Max Neal and David Neal, Delaware \nStandard Offer Service Ratepayers (Aug. 20, 2026) (“Nicholas Max Neal and \nDavid Neal Protest”) \n• Comments of North Carolina Electric Membership Corporation (Aug. 21, 2026) \n(“NCEMC Comments”) \n• Protest of Northern Virginia Electric Cooperative, Inc. (Aug. 21, 2026) (“NOVEC \nProtest”) \n• Protest and Request for Rejection of Filing or in the Alternative for Evidentiary \nHearings and/or Settlement Proceedings by Office of the Ohio Consumers’ Counsel \n(Aug. 21, 2026) (“OCC Protest”) \n• Comments of the Public Utilities Commission of Ohio’s Office of the Federal \nEnergy Advocate (Aug. 21, 2026) (“Ohio FEA Comments”) \n• Comments of Ohio Energy Leadership Council (Aug. 21, 2026) (“Ohio ELC \nComments”)"},{"page":112,"startToken":36337,"endToken":36584,"text":"iii \n• Comments of Old Dominion Electric Cooperative (Aug. 21, 2026) (“ODEC \nComments”) \n• Protest of the Pennsylvania Office of Consumer Advocate Re: Reliability Backstop \nProcurement to Address Resource Adequacy Concerns Stemming from New Load \nAdjustments (Aug. 21, 2026) (“PA OCA Protest”) \n• Comments of Persistence Analytics Group Regarding Pre-Procurement \nAssumption Verification and Revalidation (Aug. 17, 2026) (“Persistence Analytics \nComments”) \n• Supplemental Comments of Persistence Analytics Group LLC Regarding Cost-\nCausation Revalidation (Sept. 2, 2026) (“Persistence Analytics Supplemental \nComments”) \n• Comments on PJM’s Reliability Backstop Procurement Proposal on Behalf of PJM \nIndustrial Customer Coalition (Aug. 21, 2026) (“PJMICC Comments”) \n• Motion to Intervene, Limited Protest, and Request for Clarification of PPL Electric \nUtilities Corporation (Aug. 21, 2026) (“PPL Limited Protest and Request for \nClarification”) \n• Limited Protest of Public Interest Organizations (Aug. 21, 2026) (“PIOs Limited \nProtest”) \n• Comments of the Public Service Commission of West Virginia (Aug. 21, 2026) \n(“PSCWV Comments”) \n• Motion to Intervene and Protest of Retail Energy Supply Association (Aug. 21, \n2026) (“RESA Protest”) \n• Comments of Solar Energy Industries Association (Aug. 21, 2026) (“SEIA \nComments”) \n• Comments of Southern Maryland Electric Cooperative, Inc. (Aug. 21, 2026) \n(“SMECO Comments”) \n• Motion to Intervene and Request for Clarification of Talen Energy Corporation \n(Aug. 21, 2026) (“Talen Request for Clarification”) \n• Motion to Intervene and Request for Clarification, or in the Alternative, Limited \nProtest of Tract Holding Company I, LLC (Aug. 21, 2026) (“Tract Request for \nClarification or Limited Protest”) \n• Limited Protest of Vistra Corp. (Aug. 21, 2026) (“Vistra Protest”) \n• Comments of Voltus (Aug. 21, 2026) (“Voltus Comments”)"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":3,"endAt":104,"startToken":0,"endToken":823},{"p":3,"at":104,"title":"I. ANSWER","method":"printed heading","endPage":3,"endAt":116,"startToken":823,"endToken":825},{"p":3,"at":116,"title":"A. The RBP Proposal Is a Measured and Timely Response that Received","method":"printed heading","endPage":10,"endAt":655,"startToken":825,"endToken":3819},{"p":10,"at":655,"title":"B. The Role of Electric Distributors in the RBP Is Appropriately Tailored.","method":"printed heading","endPage":12,"endAt":1017,"startToken":3819,"endToken":4439},{"p":12,"at":1017,"title":"C. Nothing in Intervenors’ Protests, Comments Call into Question the","method":"printed heading","endPage":22,"endAt":415,"startToken":4439,"endToken":7415},{"p":22,"at":415,"title":"D. RBP Offsets Should Neither Be Expanded to Include Additional Types of","method":"printed heading","endPage":25,"endAt":889,"startToken":7415,"endToken":8462},{"p":25,"at":889,"title":"E. PJM Addresses Several Intervenor Requests for Clarification to the","method":"printed heading","endPage":31,"endAt":305,"startToken":8462,"endToken":10166},{"p":31,"at":305,"title":"F. PJM’s Procurement Process Is Just and Reasonable.","method":"printed heading","endPage":47,"endAt":4,"startToken":10166,"endToken":14990},{"p":47,"at":4,"title":"G. The Requirement for RBP Resources to Offer into the RPM As","method":"printed heading","endPage":55,"endAt":445,"startToken":14990,"endToken":17792},{"p":55,"at":445,"title":"H. Arguments That RBP Should Be Extended to FRR Entities Are Baseless.","method":"printed heading","endPage":56,"endAt":450,"startToken":17792,"endToken":18231},{"p":56,"at":450,"title":"I. PJM’s Proposed Cost Allocation Approach Appropriately Assigns Cost","method":"printed heading","endPage":90,"endAt":1507,"startToken":18231,"endToken":29961},{"p":90,"at":1507,"title":"D. Jaramillo on Behalf of Northern Virginia Electric Cooperative, at 4 (Va. S.C.C. Dec. 16, 2024),","method":"printed heading","endPage":107,"endAt":694,"startToken":29961,"endToken":35547},{"p":107,"at":694,"title":"II. CONCLUSION","method":"printed heading","endPage":107,"endAt":699,"startToken":35547,"endToken":35548},{"p":107,"at":699,"title":"CONCLUSION","method":"printed heading","endPage":108,"endAt":0,"startToken":35548,"endToken":35690},{"p":108,"at":0,"title":"CERTIFICATE OF SERVICE","method":"printed heading","endPage":112,"endAt":1887,"startToken":35690,"endToken":36584}]}