{"document":{"slug":"e-2-pjm-el25-49-002","title":"PJM co-location rehearing order","issued":"2026-06-18","docket":"EL25-49-002","filer":"FERC","group":"June 18 orders","kind":"order","file":"docs/orders/e-2-pjm-el25-49-002.pdf","url":"https://www.ferc.gov/media/e-2-el25-49-002","sha256":"924f3bc65ab8aa0c9bf803d704e08db658f5a598ebac95b7a8dbd7b45897e11c","pages":278,"tokens":107648,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":186,"text":"195 FERC ¶ 61,209 \nUNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nBefore Commissioners:  Laura V. Swett, Chairman; \n                                        David Rosner, Lindsay S. See, \n                                        Judy W. Chang, and David LaCerte. \n \nPJM Interconnection, L.L.C. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nDelmarva Power & Light Company \nDuke Energy Ohio, Inc. \nDuke Energy Kentucky, Inc. \nEast Kentucky Power Cooperative, Inc. \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nJersey Central Power & Light Company \nMid-Atlantic Interstate Transmission, LLC \nNeptune Regional Transmission System, LLC \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nMonongahela Power Company \nThe Potomac Edison Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nThe Dayton Power and Light Company  \nAEP Appalachian Transmission Company, Inc. \nAEP Indiana Michigan Transmission Company, Inc. \nAEP Kentucky Transmission Company, Inc. \nAEP Ohio Transmission Company, Inc. \nAEP West Virginia Transmission Company, Inc. \nAppalachian Power Company \nIndiana Michigan Power Company \nDocket Nos. EL25-49-002 \nEL25-49-000"},{"page":2,"startToken":186,"endToken":373,"text":"Docket No. EL25-49-002, et al. \n- 2 - \nKentucky Power Company \nKingsport Power Company \nOhio Power Company \nWheeling Power Company \nDuquesne Light Company \nVirginia Electric and Power Company \nLinden VFT, LLC \nCity of Cleveland, Department of Public Utilities, \nDivision of Cleveland Public Power \nCity of Hamilton, OH \nSouthern Maryland Electric Cooperative, Inc. \nOhio Valley Electric Corporation \nAMP Transmission, LLC \nSilver Run Electric, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nWabash Valley Power Association, Inc. \nKeystone Appalachian Transmission Company \nLarge Loads Co-Located at Generating Facilities  \nConstellation Energy Generation, LLC \nv.  \nPJM Interconnection, L.L.C. \nPJM Interconnection, L.L.C. \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nAD24-11-001 \n \nEL25-20-001 \n(consolidated) \n \n \n \n \nER26-1479-000 \n \nORDER ON REHEARING, CLARIFICATION, COMPLIANCE FILING, AND PAPER \nHEARING \n \n(Issued June 18, 2026) \n \n \nOn December 18, 2025, the Commission issued an order in the show cause \nproceeding in Docket No. EL25-49-000, et al., pursuant to section 206 of the Federal \nPower Act (FPA),1 finding PJM Interconnection, L.L.C.’s (PJM) Tariff unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity or \nconsistency the rates, terms, and conditions of service that apply to generators serving \n \n1 16 U.S.C. § 824e."},{"page":3,"startToken":373,"endToken":809,"text":"Docket No. EL25-49-002, et al. \n- 3 - \nCo-Located Load and Eligible Customers taking transmission service on behalf of       \nCo-Located Load.2   \n \nThe Commission directed PJM to file, within 60 days of the date of issuance of the \norder, a compliance filing to revise its Tariff to set forth specific terms and conditions \nthat an Interconnection Customer in PJM seeking to serve Co-Located Load must follow \nto effectuate a Co-Location Arrangement.  In addition, the Commission directed PJM to \nsubmit in its compliance filing revisions to its Tariff to require that the Eligible Customer \ntaking transmission service on behalf of the Co-Located Load takes one of three \ntransmission services:  (1) Network Integration Transmission Service (NITS), including a \nnew interim, non-firm transmission service available until all Network Upgrades \nnecessary to provide the requested NITS are complete (Interim NITS), (2) a new Firm \nContract Demand (FCD) transmission service, or (3) a new Non-Firm Contract Demand \n(NFCD) transmission service.3  The Commission established a paper hearing to \ndetermine the just and reasonable rates, terms, and conditions for these new transmission \nservices.   \n \nThe Commission also found the Behind the Meter Generation (BTMG) rules in the \nTariff to be no longer just and reasonable, and the Commission directed PJM to submit in \nits compliance filing revisions to its Tariff to revise the retail BTMG netting rules and to \nimplement a transition process for existing BTMG participants.4   \n \n2 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217, at P 2 (2025) (December \nOrder).  The December Order defined the Tariff as PJM’s Open Access Transmission \nTariff (OATT), the Amended and Restated Operating Agreement of PJM, and the \nReliability Assurance Agreement Among Load Serving Entities in the PJM Region.  See \nAppendix for tariff records accepted in this order. \n3 Capitalized terms used but not otherwise defined in this order have the meanings \nascribed to them in the Tariff. \n4 PJM defines BTMG as “a generation unit that delivers energy to load without \nusing the Transmission System or any distribution facilities (unless the entity that owns \nor leases the distribution facilities has consented to such use of the distribution facilities \nand such consent has been demonstrated to the satisfaction of the Office of the \nInterconnection); provided, however, that [BTMG] does not include:  (i) at any time, any \nportion of such generating unit’s capacity that is designated as a Generation Capacity \nResource; or (ii) in an hour, any portion of the output of such generating unit that is sold \nto another entity for consumption at another electrical location or into the PJM \nInterchange Energy Market.”  PJM, Intra-PJM Tariffs, OATT, § I.1 Definitions – A-B \n(21.0.0) (defining BTMG)."},{"page":4,"startToken":809,"endToken":1211,"text":"Docket No. EL25-49-002, et al. \n- 4 - \n \nOn January 16, 2026, Exelon and FirstEnergy5 timely filed a request for rehearing \nof the December Order.  On January 20, 2026, Industrials6 timely filed a request for \nclarification or, in the alternative, rehearing.  On January 20, 2026, Constellation Energy \nGeneration, LLC (Constellation) filed a request for clarification or, in the alternative, \nrehearing.  On January 20, 2026, PIOs7 filed a limited request for clarification.  On \nJanuary 20, 2026, Joint Parties8 filed a request for clarification.  On February 9, 2026, \nAndrew Hinz filed a late request for rehearing. \n \nOn February 23, 2026, in Docket No. ER26-1479-000, PJM filed its second \ncompliance filing as directed by the December Order. \n \nOn February 23, 2026, in Docket No. EL25-49-000, PJM and the Indicated TOs9 \neach submitted an initial brief to address the Commission’s paper hearing questions with \n \n5 The request for rehearing was filed only by (1) Exelon Corporation (Exelon), on \nbehalf of Atlantic City Electric Company, Baltimore Gas and Electric Company, \nCommonwealth Edison Company, Commonwealth Edison Company of Indiana, Inc., \nDelmarva Power & Light Company, PECO Energy Company, and Potomac Electric \nPower Company; and (2) FirstEnergy Service Company, as agent for its affiliates \nAmerican Transmission Systems, Incorporated, Jersey Central Power & Light Company, \nMid-Atlantic Interstate Transmission LLC, Keystone Appalachian Transmission \nCompany, The Potomac Edison Company, Monongahela Power Company and                  \nTrans-Allegheny Interstate Line Company (collectively, FirstEnergy). \n6 As to the request for clarification or, in the alternative, rehearing, Industrials are \nthe PJM Industrial Customer Coalition (PJM ICC) and the Industrial Energy Consumers \nof America (IECA). \n7 As to the request for clarification, PIOs are EarthJustice, Environmental Defense \nFund, and Sierra Club. \n8 As to the request for clarification, Joint Parties are Eolian LP, Antora Energy \nLLC, and Verrus LLC. \n9 We refer to the Indicated PJM Transmission Owners that submitted briefing \njointly in the paper hearing as Indicated TOs.  The transmission owners that submitted \nbriefing jointly in the paper hearing are:  American Electric Power Service Corporation \non behalf of its affiliates, Appalachian Power Company, Indiana Michigan Power \nCompany, Kentucky Power Company, Kingsport Power Company, Ohio Power \nCompany, Wheeling Power Company, AEP Appalachian Transmission Company, AEP \nIndiana Michigan Transmission Company, AEP Kentucky Transmission Company, AEP \nOhio Transmission Company, and AEP West Virginia Transmission Company; The \nDayton Power and Light Company d/b/a AES Ohio; Dominion Energy Services, Inc. on \nbehalf of Virginia Electric and Power Company d/b/a Dominion Energy Virginia; Duke"},{"page":5,"startToken":1211,"endToken":1611,"text":"Docket No. EL25-49-002, et al. \n- 5 - \nrespect to the new transmission services.  On March 25, 2026, and on April 24, 2026, \nparties submitted response briefs and reply briefs, respectively. \n \nIn this order, we address the requests for rehearing and clarification of the \nDecember Order, PJM’s compliance filing, and the paper hearing on the new \ntransmission services.  Pursuant to Allegheny Defense Project v. FERC,10 the rehearing \nrequests filed in this proceeding may be deemed denied by operation of law.  However, \nas permitted by section 313(a) of the FPA,11 we are modifying the discussion in the \nDecember Order and setting aside the order, in part, as discussed below.12  In addition, \nwe are granting, in part, and denying, in part, the requests for clarification.   \n \nNext, we find that PJM’s compliance filing partially complies with the directives \nof the December Order.  As such, we accept in part and reject in part PJM’s proposed \nTariff revisions, and we direct PJM to file, within 60 days of the date of issuance of this \norder, a further compliance filing. \n \nFinally, in response to the record developed in the paper hearing, we establish as \njust and reasonable certain rates, terms, and conditions for the new transmission services \ndirected in the December Order (i.e., Interim NITS, FCD transmission service, and \nNFCD transmission service).  We direct PJM to file, within 60 days of the date of \nissuance of this order, a compliance filing to revise its Tariff.  We also direct the PJM \ntransmission owners to file, within 60 days of the date of issuance of this order, a \ncompliance filing to revise the Tariff. \n \nEnergy Business Services, LLC for Duke Energy Kentucky, Inc. and Duke Energy Ohio, \nInc.; Duquesne Light Company; East Kentucky Power Cooperative; Exelon; FirstEnergy; \nPPL Electric Utilities Corporation; Public Service Electric and Gas Company; Rockland \nElectric Company; and the Southern Maryland Electric Cooperative. \n10 964 F.3d 1 (D.C. Cir. 2020) (en banc).   \n11 16 U.S.C. § 825l(a) (“Until the record in a proceeding shall have been filed in a \ncourt of appeals, as provided in subsection (b), the Commission may at any time, upon \nreasonable notice and in such manner as it shall deem proper, modify or set aside, in \nwhole or in part, any finding or order made or issued by it under the provisions of this \nchapter.”). \n12 Allegheny Def. Project, 964 F.3d at 16-17."},{"page":6,"startToken":1611,"endToken":1773,"text":"Docket No. EL25-49-002, et al. \n- 6 - \n \nContents \nI. \nBackground .............................................................................................................. - 9 - \nA. \nFebruary Order .................................................................................................. - 9 - \nB. \nDecember Order .............................................................................................. - 11 - \nII. \nNotice of Filings and Responsive Pleadings ...................................................... - 14 - \nA. \nPJM’s Compliance Filing ............................................................................... - 14 - \nB. \nPaper Hearing on New Transmission Services ............................................... - 15 - \nIII. \nProcedural Matters ............................................................................................. - 16 - \nIV. \nRequests for Rehearing and/or Clarification ...................................................... - 18 - \nA. \nJurisdiction ...................................................................................................... - 19 - \n1. Sales for Resale in Interstate Commerce ........................................................ - 19 - \n2. Retail Allocation of Commission-Jurisdictional Rates ................................... - 20 - \n3. Retail BTMG................................................................................................... - 22 - \n4. Retail Backup Service ..................................................................................... - 24 - \nB. \nShow Cause Findings ...................................................................................... - 26 - \n1. Overview, Transmission Service, Regulation and Black Start ....................... - 26 - \n2. Retail BTMG Netting Rules ........................................................................... - 41 - \n3. Transmission Service Options for BTMG ...................................................... - 50 - \nC. \nReplacement Rate ........................................................................................... - 52 - \n1. Transmission Services .................................................................................... - 52 - \n2. Necessary Study Process for Existing Interconnection Customers ................ - 87 - \n3. New Generators Serving Co-Located Load .................................................... - 95 - \nD. \nInformational Report ....................................................................................... - 97 - \n1. December Order .............................................................................................. - 97 - \n2. Request for Clarification ................................................................................. - 98 - \n3. Determination.................................................................................................. - 99 - \nV. \nCompliance ......................................................................................................... - 99 - \nA. \nBTMG Rules ................................................................................................... - 99 - \n1. Materiality Threshold ...................................................................................... - 99 - \n2. Grandfathering and Transition Period .......................................................... - 116 -"},{"page":7,"startToken":1773,"endToken":1925,"text":"Docket No. EL25-49-002, et al. \n- 7 - \n3. QFs and Cogeneration Facilities ................................................................... - 121 - \nB. \nTransmission Service .................................................................................... - 127 - \n1. December Order ............................................................................................ - 127 - \n2. PJM Compliance Filing ................................................................................ - 129 - \n3. Pleadings ....................................................................................................... - 130 - \n4. Answers ......................................................................................................... - 131 - \n5. Determination................................................................................................ - 132 - \nC. \nNecessary Studies ......................................................................................... - 135 - \n1. December Order ............................................................................................ - 135 - \n2. PJM Compliance Filing ................................................................................ - 136 - \n3. Pleadings ....................................................................................................... - 136 - \n4. Determination................................................................................................ - 139 - \nD. \nOther .............................................................................................................. - 143 - \n1. December Order ............................................................................................ - 143 - \n2. PJM Compliance Filing ................................................................................ - 144 - \n3. Pleadings ....................................................................................................... - 147 - \n4. Answers ......................................................................................................... - 150 - \n5. Determination................................................................................................ - 150 - \nE. \nEffective Date ............................................................................................... - 154 - \n1. PJM Compliance Filing ................................................................................ - 154 - \n2. Effective Date Pleadings ............................................................................... - 154 - \n3. Determination................................................................................................ - 155 - \nVI. \nPaper Hearing ................................................................................................... - 155 - \nA. \nRates, Terms, and Conditions for Firm and Non-Firm Contract Demand \nTransmission Service .............................................................................................. - 156 - \n1. December Order ............................................................................................ - 156 - \n2. Nature of FCD and NFCD Transmission Services ....................................... - 157 - \n3. Study Process ................................................................................................ - 171 - \n4. Rates and Charges ......................................................................................... - 179 - \n5. Other .............................................................................................................. - 193 - \nB. \nAdditional Charge for Eligible Customers Taking FCD and/or NFCD \nTransmission Service .............................................................................................. - 199 - \n1. December Order ............................................................................................ - 199 -"},{"page":8,"startToken":1925,"endToken":2080,"text":"Docket No. EL25-49-002, et al. \n- 8 - \n2. Initial Briefs .................................................................................................. - 200 - \n3. Response Briefs............................................................................................. - 201 - \n4. Reply Briefs .................................................................................................. - 204 - \n5. Answers ......................................................................................................... - 206 - \n6. Determination................................................................................................ - 207 - \nC. \nInterconnection Requirements and Operational Practices for Necessary Control \nTechnologies and/or Protection Systems ................................................................ - 208 - \n1. Initial Briefs .................................................................................................. - 208 - \n2. Response Briefs............................................................................................. - 209 - \n3. Reply Briefs .................................................................................................. - 211 - \n4. Answer .......................................................................................................... - 214 - \n5. Determination................................................................................................ - 214 - \nD. \nPenalty Charge or Other Remedial Action for New Transmission Services - 218 - \n1. Initial Briefs .................................................................................................. - 218 - \n2. Response Briefs............................................................................................. - 220 - \n3. Reply Briefs .................................................................................................. - 223 - \n4. Answer .......................................................................................................... - 227 - \n5. Determination................................................................................................ - 227 - \nE. \nAnti-Toggling Mechanisms for Firm Contract Demand Transmission Service ..... - \n237 - \n1. Initial Briefs .................................................................................................. - 237 - \n2. Response Briefs............................................................................................. - 238 - \n3. Determination................................................................................................ - 238 - \nF. \nCommunications, Alarm, SCADA, or Other Requirements ......................... - 240 - \n1. Initial Briefs .................................................................................................. - 240 - \n2. Response Briefs............................................................................................. - 240 - \n3. Determination................................................................................................ - 240 - \nG. \nCurtailment Procedures for Interim NITS and Non-Firm Contract Demand \nTransmission Service .............................................................................................. - 241 - \n1. Initial Briefs .................................................................................................. - 241 - \n2. Response Briefs............................................................................................. - 242 - \n3. Reply Briefs .................................................................................................. - 243 - \n4. Answers ......................................................................................................... - 244 -"},{"page":9,"startToken":2080,"endToken":2278,"text":"Docket No. EL25-49-002, et al. \n- 9 - \n5. Determination................................................................................................ - 244 - \nH. \nRates, Terms, and Conditions for Interim NITS ........................................... - 246 - \n1. Initial Briefs .................................................................................................. - 246 - \n2. Response Briefs............................................................................................. - 247 - \n3. Reply Briefs .................................................................................................. - 250 - \n4. Answers ......................................................................................................... - 251 - \n5. Determination................................................................................................ - 252 - \nI. \nAnnual Report on New Transmission Services ................................................ - 256 - \nJ. \nProposed Effective Date ................................................................................... - 258 - \n1. Initial Briefs .................................................................................................. - 258 - \n2. Response Briefs............................................................................................. - 259 - \n3. Reply Briefs .................................................................................................. - 262 - \n4. Answer .......................................................................................................... - 264 - \n5. Determination................................................................................................ - 264 - \nK. \nAdditional Arguments ................................................................................... - 265 - \n1. Behind the Meter Generation ........................................................................ - 265 - \n2. Reliability Backstop Auction ........................................................................ - 265 - \n3. Eligible Customer Requirements .................................................................. - 267 - \n4. Demand Side Pathways ................................................................................. - 268 - \n5. Interconnection.............................................................................................. - 269 - \n6. Co-Location Arrangement with Electric Storage Resource ......................... - 270 - \n \nI. \nBackground \nA. \nFebruary Order \n \nIn February 2025, the Commission instituted a new proceeding in Docket                     \nNo. EL25-49-000 to examine whether the Tariff remains just and reasonable and not \nunduly discriminatory or preferential without provisions addressing with sufficient clarity \nor consistency the rates, terms, and conditions of service that apply to co-location \narrangements.13  The February Order defined Co-Located Load as a “‘configuration [that] \nrefers to end-use customer load that is physically connected to the facilities of an existing \n \n13 PJM Interconnection, L.L.C., 190 FERC ¶ 61,115, at P 2 (2025) (February \nOrder)."},{"page":10,"startToken":2278,"endToken":2717,"text":"Docket No. EL25-49-002, et al. \n- 10 - \nor planned Customer Facility on the Interconnection Customer’s side of the Point of \nInterconnection to the PJM Transmission System.’”14  As in the February Order, when \nreferring to both the Co-Located Load and the associated generator, we will use the term \nCo-Location Arrangement. \n \nAs explained in the February Order, Co-Location Arrangements are becoming \nincreasingly common in PJM and, since the issuance of the February Order, entities \ncontinue to raise issues involving Co-Location Arrangements with the Commission.15  \nThe Commission set forth, in the February Order, the principles relating to the \nCommission’s jurisdiction over the matters relevant to Co-Location Arrangements.16  The \nCommission also made several preliminary findings about the justness and \nreasonableness of the Tariff.  First, the Commission found that the Tariff appears to be \nunjust and unreasonable or unduly discriminatory or preferential because it does not \ncontain provisions addressing with sufficient clarity or consistency the rates, terms, and \n \n14 Id. P 3 & n.4.  We note that, in the February Order, the Commission adopted \nthis definition from the Guidance Document that PJM developed on Co-Located Load.  \nSee id.  PJM rescinded this document pending Commission guidance in this docket.  PJM \nMarch 24, 2025 Response at 33.  Prior to PJM’s transition to its new interconnection \nprocess, PJM used the terms Interconnection Customer and Generation Interconnection \nCustomer.  The Tariff defines Generation Interconnection Customer as “an entity that \nsubmits an Interconnection Request to interconnect a new generation facility or to \nincrease the capacity of an existing generation facility interconnected with \nthe Transmission System in the PJM Region.”  PJM, Intra-PJM Tariffs, OATT, § I.1 \nDefinitions – G – H) (9.0.1) (defining Generation Interconnection Customer).  The \nTariff’s new rules for generation interconnection, effective January 3, 2023, utilize the \nterms Project Developer and Generation Project Developer.  The Tariff defines \nGeneration Project Developer as “an entity that submits a Generation Interconnection \nRequest to interconnect a new generation facility or to increase the capacity of an existing \ngeneration facility interconnected with the Transmission System in the PJM Region.”  \nPJM, Intra-PJM Tariffs, OATT, § VIII subpt. A 400 (Definitions G) (0.1.0) (defining \nGeneration Project Developer).  For simplicity, in this order, and consistent with the \nFebruary Order and December Order, the Commission will use the term Interconnection \nCustomer to refer to both the Tariff definitions of Generation Interconnection Customer \nand Generation Project Developer. \n15 See, e.g., PJM Interconnection, L.L.C., 191 FERC ¶ 61,112 (2025) (accepting \nnecessary studies agreement).  The February Order consolidated the new show cause \nproceeding with a pending complaint proceeding in Docket No. EL25-20-000 involving \nCo-Located Load.   \n16 February Order, 190 FERC ¶ 61,115 at P 66."},{"page":11,"startToken":2717,"endToken":3064,"text":"Docket No. EL25-49-002, et al. \n- 11 - \nconditions of service that apply to Co-Location Arrangements.17  In addition, the \nCommission preliminarily found that this lack of applicable Tariff provisions raises the \npotential for undue discrimination or preferential treatment.18  \n \nAs to specific concerns raised regarding Co-Location Arrangements, the \nCommission found that the Tariff may be unjust, unreasonable, unduly discriminatory, or \npreferential because it does not specify the transmission service that Co-Location \nArrangements must take, if any, or otherwise provide a process to ensure that                          \nCo-Location Arrangements are paying for the benefits they receive from the transmission \nsystem consistent with cost causation principles, which provide that all                      \nCommission-jurisdictional rates and charges must “reflect to some degree the costs \nactually caused by the customer who must pay for them,” and that costs must be allocated \nin a manner that is at least roughly commensurate with the benefits that entity receives.19  \nThe Commission also found that the absence of rates, terms, and conditions of \ninterconnection service specific to Co-Location Arrangements, and, especially regarding \nstudies of the impacts of those arrangements, may render the Tariff unjust and \nunreasonable or unduly discriminatory or preferential.20  Moreover, the Commission \nfound that the absence of rates, terms, and conditions governing the use and sale of \nancillary services and black start services by Co-Location Arrangements may render the \nTariff unjust and unreasonable or unduly discriminatory or preferential.21  The \nCommission directed briefing to build a record on these issues as well as a possible \nreplacement rate. \nB. \nDecember Order \n \nIn the December Order, the Commission found the Tariff unjust and unreasonable \nbecause it does not contain provisions addressing with sufficient clarity or consistency \nthe rates, terms, and conditions of service that apply to Interconnection Customers \nserving Co-Located Load and Eligible Customers taking transmission service on behalf \n \n17 Id. P 74. \n18 Id. P 75. \n19 Id. PP 74-78 (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d \n1361, 1368 (D.C. Cir. 2004); Ill. Com. Comm’n v. FERC, 576 F.3d 470, 476 (7th Cir. \n2009)). \n20 Id. P 79. \n21 Id. P 82."},{"page":12,"startToken":3064,"endToken":3434,"text":"Docket No. EL25-49-002, et al. \n- 12 - \nof Co-Located Load.22  The Commission explained that the absence of such provisions \nleaves entities unable to determine what steps they must take to effectuate Co-Location \nArrangements and creates uncertainty that has resulted in disparate treatment in PJM \nbecause transmission owners have taken different approaches to performing the necessary \nsteps that apply to Interconnection Customers seeking to serve Co-Located Load through \na Co-Location Arrangement.23  The Commission found that the absence of such \nprovisions also introduces the risk that Co-Located Load may benefit from regulation and \nblack start services without contributing to cost recovery for such services.24   \n \nSpecifically, the Commission found the Tariff unjust and unreasonable because \nthere is a lack of sufficient clarity or consistency as to the rates, terms, and conditions of \nservice that apply to Interconnection Customers serving Co-Located Load.25  As part of \nthe replacement rate, the Commission directed PJM to file revisions to the generation \ninterconnection procedures of the Tariff, including to require an Interconnection \nCustomer who will use its generator to serve Co-Located Load to specify an Eligible \nCustomer who will take transmission service on behalf of the Co-Located Load, and \nrevisions to clarify its Necessary Study process.26  The Commission also directed PJM to \nrevise its Tariff to clarify that an Interconnection Customer seeking to serve a                            \nCo-Located Load with a newly interconnecting generator may:  (1) request \ninterconnection service at a level below its maximum facility output; (2) use existing \nprocedures in the Tariff to accelerate the study of the interconnection service request if \nthe request has no cost allocation for Network Upgrades and does not require further \nstudies; (3) request provisional interconnection service; and (4) request Surplus \nInterconnection Service.27   \n \nThe Commission also found the Tariff unjust and unreasonable because it does not \ninclude transmission services that reflect Eligible Customers taking service on behalf of \nCo-Located Loads that are willing and able to limit their energy withdrawals from the \ntransmission system under certain conditions.28  The Commission further found the Tariff \n \n22 December Order, 193 FERC ¶ 61,217 at P 175. \n23 Id. \n24 Id. \n25 Id. P 176. \n26 Id. PP 176, 187-192, 225-230. \n27 Id. PP 176, 231-235. \n28 Id. PP 177, 193."},{"page":13,"startToken":3434,"endToken":3837,"text":"Docket No. EL25-49-002, et al. \n- 13 - \nunjust and unreasonable because it does not address charges related to Co-Located \nLoads’ use of regulation and black start services, which introduces the risk that                       \nCo-Located Load may benefit from regulation and black start services without \ncontributing to cost recovery for such services and, thereby, the risk that costs may be \nallocated entirely to other transmission customers and passed through to residential \ncustomers, among others.29  The Commission found that NITS charged on a gross \ndemand basis is one just and reasonable transmission service option for Eligible \nCustomers taking transmission service on behalf of Co-Located Loads, but it is not the \nonly option.30  The Commission thus directed PJM to revise its Tariff to create three new \ntransmission services (i.e., Interim NITS, FCD transmission service, and NFCD \ntransmission service) that reflect that Eligible Customers taking service on behalf of     \nCo-Located Loads are willing and able to limit their energy withdrawals from the \ntransmission system under certain conditions.31  Specific to these new transmission \nservices, the Commission established paper hearing procedures to determine the just and \nreasonable rates, terms, and conditions for such services.32   \n \nThe Commission also found the existing retail BTMG netting rules in the Tariff to \nbe unjust and unreasonable.  PJM’s existing Tariff allows load serving entities (LSE) that \nprovide service to loads with qualifying BTMG to reduce their costs by netting output \nfrom BTMG in the calculation of their peak demand for the purpose of determining NITS \ncharges.33  The Commission explained that these retail BTMG netting rules may lead to \nboth reliability and resource adequacy risks because PJM, per its Tariff, is obligated to \nserve transmission customers using BTMG but does not consider such customers’ full \ngross load in transmission and resource adequacy planning.34  Thus, the Commission \ndirected PJM to revise its retail BTMG netting rules.35  In recognizing concerns about the \npotential impacts on existing BTMG customers, the Commission directed PJM to \nmaintain the current retail BTMG netting rules for customers that fall below a new MW \nmateriality threshold for the amount of load at a particular electrical location that \nNetwork Customers may net using BTMG and to implement a two-part transition process \n \n29 Id. P 177. \n30 Id. PP 195-196. \n31 Id. PP 178, 200-202, 206, 208-218. \n32 Id. PP 178, 194, 203, 207, 219. \n33 Id. P 7. \n34 Id. PP 179, 186. \n35 Id. PP 179, 221."},{"page":14,"startToken":3837,"endToken":4199,"text":"Docket No. EL25-49-002, et al. \n- 14 - \nfor retail BTMG including:  (1) the establishment of a three-year transition period; and \n(2) the ability to grandfather certain entities with existing contracts.36   \nII. \nNotice of Filings and Responsive Pleadings \nA. \nPJM’s Compliance Filing \n \nNotice of PJM’s compliance filing in Docket No. ER26-1479-000 was published \nin the Federal Register, 91 Fed. Reg. 9849 (Feb. 27, 2026) with interventions and \nprotests due on or before March 16, 2026. \n \nTimely motions to intervene were filed by American Forest & Paper Association \n(AF&PA); PJM Industrial Customer Coalition (PJM ICC); Industrial Energy Consumers \nof America (IECA); Monitoring Analytics, LLC, acting in its capacity as the Independent \nMarket Monitor for PJM (Market Monitor); LS Power Development, LLC; Enchanted \nRock, LLC (Enchanted Rock); Illinois Municipal Electric Agency; American Clean \nPower Association; New Jersey Division of Rate Counsel; PJM Power Providers Group; \nAmerican Electric Power Service Corporation; Exelon Corporation; Constellation Energy \nGeneration, LLC (Constellation); Public Citizen, Inc.; East Kentucky Power Cooperative, \nInc.; Clean Energy Buyers Association; Edison Electric Institute; Maryland Office of \nPeople’s Counsel (Maryland OPC); EDF Power Solutions, Inc. (EDFps); Solar Energy \nIndustries Association (SEIA); Advanced Energy United (AEU); Buckeye Power, Inc.; \nElectric Power Supply Association; Duquesne Light Company; North Carolina Electric \nMembership Corporation; New Jersey Board of Public Utilities; Appalachian Voices; \nPennsylvania Office of Consumer Advocate; Public Service Electric and Gas Company, \nPSEG Power LLC and PSEG Energy Resources & Trade LLC (collectively, PSEG \nCompanies); Old Dominion Electric Cooperative (ODEC); National Railroad Passenger \nCorporation (Amtrak); Dominion Energy Services, Inc.; Crusoe Energy Systems, Inc. \n(Crusoe); Consolidated Edison Company of New York, Inc.; PPL Electric Utilities \nCorporation (PPL); Rockland Electric Company; Illinois Industrial Energy Consumers; \nAmerican Municipal Power, Inc. (AMP); Grid Reform; Invenergy Renewables LLC and \nInvenergy Thermal LLC (Invenergy); Data Center Coalition (DCC); Eastman Chemical \nCompany (Eastman); Northern Virginia Electric Cooperative, Inc. (NOVEC); Vistra \nCorp. (Vistra); Mainspring Energy; Northeastern REMC; Borough of Chambersburg, \nPennsylvania; Capital Power Corporation; Eolian, L.P. (Eolian); Antora Energy, Inc. \n(Antora); Calibrant Energy (Calibrant); Convergent Energy and Power (Convergent); and \nVerrus, LLC (Verrus). \n \nMotions to intervene out of time were filed by Arkon Energy Hannibal and Office \nof the Illinois Attorney General. \n \n36 Id. PP 179, 221, 223-224."},{"page":15,"startToken":4199,"endToken":4665,"text":"Docket No. EL25-49-002, et al. \n- 15 - \n \nTimely comments and/or protests were filed by Eastman; EDFps; Digital Power \nNetwork; Vistra; Maryland OPC; AEU/SEIA; Eolian, Antora, Calibrant, Convergent, \nMainspring, and Verrus (together, Joint Parties); Calibrant, Antora, Convergent, Eolian, \nand Mainspring (together, BTMG Parties); Invenergy; Energy Artisans, LLC (Energy \nArtisans); DCC; PJM ICC, IECA, AF&PA (collectively, Industrials) and Amtrak \n(Industrials/Amtrak); Digital Power Network; Crusoe; AMP; Appalachian Voices; and \nConstellation. \n \nOn April 8, 2026, Constellation filed a motion for leave and supplemental protest \nin this compliance proceeding and in Docket No. ER26-1088-000.  On April 14, 2026, \nExelon filed an answer to Constellation’s motion.  On April 24, 2026, Indicated TOs filed \na motion for leave to answer and answer to certain protests and comments.  On May 8, \n2026, the BTMG Parties and Industrials/Amtrak each filed a motion for leave to answer \nand answer the Indicated TOs’ April 24 answer.  On May 12, 2026, Eastman filed a \nmotion for leave to answer and answer the Indicated TOs’ April 24 answer.  On June 3, \n2026, Indicated TOs filed a motion for leave to answer and answer. \n \nSeveral parties filed briefs for the paper hearing in Docket No. EL25-49-000 and \nfiled these submissions in this compliance proceeding as well.  Specifically, in this \ncompliance proceeding:  on March 25, 2026, Enchanted Rock filed its reply brief; on \nMarch 26, 2026, Alliance to Save Energy filed comments; and on April 24, 2026, \nEarthjustice filed its reply brief. \nB. \nPaper Hearing on New Transmission Services \n \nOn February 23, 2026, in Docket No. EL25-49-000, PJM and Indicated TOs each \nsubmitted an initial brief.  On March 25, 2026, response briefs were submitted by: \nMarket Monitor; Geronimo Power, LLC; AEU/SEIA; Constellation; Eolian, Antora, \nCalibrant, Convergent, Mainspring, Verrus, and U.S. Energy Storage Coalition \n(collectively, Joint Co-Location Developers); Vistra; ODEC; Enchanted Rock; Indicated \nTOs; Industrials/Amtrak; NOVEC; DCC; and Alliance to Save Energy (Alliance).  On \nApril 24, 2026, reply briefs were submitted by: Earthjustice; ODEC; PJM; Maryland \nOPC; Constellation; Indicated TOs; Joint Co-Location Developers; and \nIndustrials/Amtrak.  On May 7, 2026, Enchanted Rock filed a motion for leave to answer \nand answer to PJM’s reply brief.  On May 11, 2026, Constellation filed a motion for \nleave to answer and answer to PJM’s and Indicated TOs’ reply briefs.  On May 21, 2026, \nGeronimo Power filed a motion for leave to answer and answer to PJM’s and Indicated \nTOs’ reply briefs.  On May 28, 2026, Indicated TOs filed a motion for leave to answer \nand answer to various reply briefs and Constellation’s May 11 answer.  \n \nOn December 29, 2025, American Clean Power Association filed a motion to \nintervene out of time in this proceeding.  On January 12, 2026, Vitol, Inc. filed a motion \nto intervene out of time in this proceeding.  On January 13, 2026, Pennsylvania Office of"},{"page":16,"startToken":4665,"endToken":5111,"text":"Docket No. EL25-49-002, et al. \n- 16 - \nConsumer Advocate filed a motion to intervene out of time in this proceeding.  On \nJanuary 16, 2026, Voltus, Inc. filed a motion to intervene out of time in this proceeding.  \nOn January 16, 2026, Emerald AI submitted comments out-of-time in Docket                              \nNo. EL25-49-000.  On January 26, 2026, Andrew D. Hinz filed a motion to intervene out \nof time and comments.  On March 20, 2026, Amtrak and AF&PA each filed a motion to \nintervene out of time in this proceeding.  On March 25, 2026, Calibrant, Convergent, \nVerrus, and U.S. Energy Storage Coalition filed a motion to intervene out of time in this \nproceeding. \nIII. \nProcedural Matters \n \nPursuant to Rule 214 of the Commission’s Rules of Practice and Procedure,                         \n18 C.F.R. § 385.214 (2025), the notices of intervention and timely, unopposed motions to \nintervene in Docket Nos. ER26-1479-000 and EL25-49-000 serve to make the entities \nthat filed them parties to these proceedings. \n \nPursuant to Rule 214(d) of the Commission’s Rules of Practice and Procedure,               \n18 C.F.R. § 385.214(d), we grant the late-filed motions to intervene in Docket                       \nNos. ER26-1479-000 and EL25-49-000 given these entities’ interests in the proceedings, \nthe early stage of the proceedings, and the absence of undue prejudice or delay.  \nInterventions in Docket No. EL25-49-000 are prospective only and such entities may not \nchallenge the December Order. \n \nWe note that Verrus did not intervene until after the December Order.  When, as \nhere, late intervention is sought after the issuance of a dispositive order, the prejudice to \nother parties and burden upon the Commission of granting the late intervention may be \nsubstantial.  Thus, movants bear a higher burden to demonstrate good cause for granting \nsuch late intervention.37  Verrus indicates the proceeding has changed significantly with \nthe initiation of the paper hearing proceeding.38  We do not find this explanation to be \nsufficient to meet the higher burden to show good cause for granting intervention \nfollowing a dispositive order.  As discussed above, we grant Verrus’s motion to intervene \nas-of the filing date (March 25, 2026); however, we dismiss it to the extent Verrus joins \nEolian and Antora in the request for clarification of the December Order.39 \n \n37 PJM Interconnection, L.L.C., 167 FERC ¶ 61,209, at P 24 (2019); PJM \nInterconnection, L.L.C., 157 FERC ¶ 61,193, at P 10 (2016).   \n38 Reply Brief of Joint Co-Location Developers and Motion to Intervene                        \nOut-of-Tome of Calibrant, Convergent, U.S. Energy Storage Coalition, and Verrus at 6. \n39 PJM Interconnection, L.L.C., 157 FERC ¶ 61,193 at P 10; Pac. Gas & Elec. \nCo., 100 FERC ¶ 61,097, at P 5 (2002)."},{"page":17,"startToken":5111,"endToken":5516,"text":"Docket No. EL25-49-002, et al. \n- 17 - \n \nRule 213(a)(2) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. \n§ 385.213(a)(2) (2025), prohibits an answer to a protest or answer unless otherwise \nordered by the decisional authority.  We accept the answers submitted in Docket Nos. \nEL25-49-000 and in ER26-1479-000, as well as Constellation’s supplemental protest, \nbecause they have provided information that assisted us in our decision-making process. \n \nOn February 2, 2026, Constellation filed a motion for leave and answer to Exelon \nand FirstEnergy’s request for rehearing.  On February 12, 2026, Exelon and FirstEnergy \nfiled an answer in opposition to that motion.  On February 19, 2026, the Pennsylvania \nOffice of Consumer Advocate filed a motion for leave to answer and answer in support of \nIndustrials’ request for clarification or rehearing.40  On February 5 and March 9, 2026, \nrespectively, Market Monitor and PJM filed answers and motions for leave to answer \nConstellation’s request for clarification or rehearing.  On February 20 and March 24, \n2026, Constellation filed motions for leave and answers to, respectively, Market \nMonitor’s and PJM’s answers.  Rule 713(d) of the Commission’s Rules of Practice and \nProcedure41 prohibits an answer to a request for rehearing.42  Accordingly, we deny these \nmotions and we reject these answers filed by Constellation, Exelon and FirstEnergy, \nPennsylvania Office of Consumer Advocate, Market Monitor, and PJM.43 \n \nOn February 9, 2026, Andrew Hinz filed a request for rehearing.  Pursuant to \nsection 313(a) of the FPA,44 an aggrieved party must file an application for rehearing \nwithin 30 days after the issuance of the Commission’s order; in this case, that deadline is \n \n40 Pennsylvania Office of Consumer Advocate is not a party to this proceeding \nwith respect to rehearing or clarification of the December Order and therefore may not \nfile an answer to a request for rehearing or clarification.  \n41 18 C.F.R. § 385.713(d)(1) (2025). \n42 Id. \n43 We note that the Pennsylvania Office of Consumer Advocate’s, Market \nMonitor’s, and PJM’s motions and answers responded to requests for clarification and, in \nthe alternative, rehearing.  Because the Commission has discretion in how to characterize \npleadings and examines the substance of pleadings, we construe these pleadings as \nultimately functioning in substance to respond to requests for rehearing and thus treat \nthem as such.  Sw. Power Pool, Inc., 182 FERC ¶ 61,083, at P 14 (2023).  \n44 16 U.S.C. § 825l(a)."},{"page":18,"startToken":5516,"endToken":5939,"text":"Docket No. EL25-49-002, et al. \n- 18 - \nno later than 5:00 PM U.S. Eastern Time45 on January 19, 2026.  Because the 30-day \nrehearing deadline is a statutory requirement, it cannot be waived or extended.46  \nTherefore, we reject Andrew Hinz’s request for rehearing as untimely.   \nIV. \nRequests for Rehearing and/or Clarification \n \nAs discussed further below, we sustain our finding that the Tariff is unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity or \nconsistency the rates, terms, and conditions of service that apply to Interconnection \nCustomers serving Co-Located Load and Eligible Customers taking transmission service \non behalf of Co-Located Load.47  We also sustain our finding that the Tariff is unjust and \nunreasonable because it does not include transmission services that reflect the willingness \nand ability of an Eligible Customer taking service on behalf of a Co-Located Load to \nlimit its energy withdrawals from the transmission system under certain conditions.48  As \na replacement rate, we continue to direct PJM to establish the new transmission services \ndiscussed in the December Order.49   \n \nWe also set aside, in part, the December Order; we find that requiring Eligible \nCustomers taking transmission service on behalf of load with BTMG to take NITS, \nwithout the option to instead take such alternative transmission services, would be unjust \nand unreasonable for the same reasons we made the same finding in the December Order \nwith respect to Eligible Customers taking transmission service on behalf of Co-Located \nLoad.  As a replacement rate, we direct PJM to revise its Tariff to extend the new \ntransmission services to Eligible Customers taking service on behalf of load with BTMG. \n \n45 The Commission’s regular business hours end at 5:00 p.m., U.S. Eastern Time. \n18 C.F.R. § 375.101(c) (2025); 18 C.F.R. § 385.2003(c) (2025); FERC, eFiling User \nGuide (May 23, 2024), https://www.ferc.gov/media/efiling-user-guide. \n46 See, e.g., City of Campbell v. FERC, 770 F.2d 1180, 1183 (D.C. Cir. 1985) \n(“The 30-day time requirement of the [FPA] is as much a part of the jurisdictional \nthreshold as the mandate to file for a rehearing.”); Bos. Gas Co. v. FERC, 575 F.2d 975, \n977-98, 979 (1st Cir. 1978) (describing identical rehearing provision of Natural Gas Act \nas “a tightly structured and formal provision” and holding that “[n]either the Commission \nor the courts are given any form of jurisdictional discretion”). \n47 December Order, 193 FERC ¶ 61,217 at P 159. \n48 Id. \n49 Id. P 160."},{"page":19,"startToken":5939,"endToken":6251,"text":"Docket No. EL25-49-002, et al. \n- 19 - \n \nWe also continue to find that PJM’s retail BTMG netting rules are unjust and \nunreasonable.50  We continue to direct PJM to revise the Tariff’s retail BTMG netting \nrules.51  We also set aside, in part, the December Order; we find that it is just and \nreasonable to allow certain cogeneration Qualifying Facilities (QFs) that are Network \nCustomers to be able to net by using BTMG, without being subject to the new materiality \nthreshold, if they demonstrate that they are integrated with load such that, when their \ngenerating facility trips offline, the load follows. \n \nWe also continue to direct PJM to clarify its interconnection procedures and \nagreements to ensure that it is clear to both new and existing Interconnection Customers \nhow to interconnect in a Co-Location Arrangement.52 \nA. \nJurisdiction \n1. \nSales for Resale in Interstate Commerce \na. \nDecember Order \n \nIn the December Order, the Commission found that several aspects of Co-Location \nArrangements fall squarely within the jurisdiction of the states.  In particular, the \nCommission affirmed that “states have authority over their generation resource mix, \nincluding through their siting authority” and further explained that “[t]his authority \nmeans that which generating facilities are sited and allowed to serve Co-Located Load is \nalso a question of state law.”53  In addition, the Commission “decline[d] in this \nproceeding to comprehensively address jurisdictional matters regarding the \ninterconnection of retail loads served through a Co-Location Arrangement to the \ninterstate transmission system.”54 \nb. \nRequest for Clarification and/or Rehearing \n \nConstellation requests that the Commission clarify that the Commission has \njurisdiction over the wholesale sale of energy by a generator to a retail supplier even if \nthe retail supplier then resells that energy to a Co-Located Load.  Constellation states that \n \n50 Id. P 186.  \n51 Id. PP 221-224.  \n52 Id. P 161. \n53 Id. P 169. \n54 Id. P 170."},{"page":20,"startToken":6251,"endToken":6629,"text":"Docket No. EL25-49-002, et al. \n- 20 - \nthe December Order is unclear in that it states that “states have authority over their \ngeneration resource mix, including through their siting authority” and that “which \ngenerating facilities are sited and allowed to serve Co-Located Load is also a question of \nstate law.”55  Constellation explains that generators often do not serve Co-Located Load \ndirectly and instead sell electricity at wholesale to an entity, such as a retail supplier, that \nwill then engage in the ultimate retail sale to the Co-Located Load.  In such \ncircumstances, Constellation argues that such sales for resale are exclusively within the \nCommission’s jurisdiction.56 \nc. \nDetermination \n \nIn response to Constellation’s request for clarification or rehearing, we reiterate \nthat, where a generator sells electricity at wholesale in interstate commerce to another \nentity that then resells that electricity at retail to a Co-Located Load, the generator’s sale \nfor resale is exclusively within the Commission’s jurisdiction.57  Thus, state authority \ndoes not extend to the wholesale sale of energy by a generator to a retail supplier, \nregardless of the specific type of ultimate retail customer.  However, as the Commission \nexplained in the December Order, both “which generating facilities are sited” and which \ngenerating facilities are “allowed to serve Co-Located Load” are “question[s] of state \nlaw.”58   \n2. \nRetail Allocation of Commission-Jurisdictional Rates \na. \nDecember Order \n \nIn the December Order, the Commission held that “states have exclusive \njurisdiction over how the costs assigned to Eligible Customers on behalf of Co-Located \nLoad taking Commission-jurisdictional transmission services,” including the new \ntransmission services, “are allocated to individual retail consumers that are Co-Located \nLoad, just as states have exclusive jurisdiction over how to allocate the costs of all \n \n55 Constellation Request for Clarification or Rehearing at 6-7 (citing December \nOrder, 193 FERC ¶ 61,217 at P 169) (emphasis in original).  \n56 Id. at 6-7 (citing 16 U.S.C. § 824(b)(1); Orangeburg v. FERC, 862 F.3d 1071, \n1086-87 (D.C. Cir. 2017)). \n57 Orangeburg, 862 F.3d at 1086-87 (“FERC—not state commissions—has \n‘exclusive authority to regulate the . . . sale at wholesale of electric energy in interstate \ncommerce.’”) (quoting New Eng. Power Co. v. N.H., 455 U.S. 331, 340 (1982)). \n58 December Order, 193 FERC ¶ 61,217 at P 169."},{"page":21,"startToken":6629,"endToken":6993,"text":"Docket No. EL25-49-002, et al. \n- 21 - \nCommission-jurisdictional rates (including for energy, capacity, and transmission) among \nretail customers, including allocating costs among different classes of retail customers.”59 \nb. \nRequest for Clarification and/or Rehearing \n \nConstellation requests that the Commission clarify that states do not have \nunlimited authority over how to allocate the costs of all Commission-jurisdictional rates \nand that they cannot use their authority over retail allocation to indirectly regulate the \ninterconnection of generators serving Co-Located Load.60  For example, Constellation \nclaims that a state cannot impose via the exercise of its jurisdiction over retail sales a \nrequirement that attempts to prohibit a transaction that the Commission says is \npermitted.61  Constellation asserts that some utilities have asked their state commission \nfor authority to condition retail service in the state on the load’s acceptance of a \nTransmission Security Agreement that calculates its security requirement based on a \ngross NITS rate despite the fact that the Commission has said that other rates must be \nmade available.62  Constellation argues that the December Order is unclear in that it \nprovides that “states have exclusive jurisdiction over how to allocate the costs of all \nCommission-jurisdictional rates (including for energy, capacity, and transmission) among \nretail customers, including allocating costs among different classes of retail customers.”63 \nc. \nDetermination \n \nIn response to Constellation’s request, we deny clarification and sustain the \nDecember Order.  In the December Order, the Commission appropriately explained that \n“states have exclusive jurisdiction over how to allocate the costs of all                      \nCommission-jurisdictional rates (including for energy, capacity, and transmission) among \nretail customers, including allocating costs among different classes of retail customers.”64  \nOn the other hand, we note that states “may not seek to achieve ends, however legitimate, \nthrough regulatory means that intrude on FERC’s authority over interstate wholesale \n \n59 Id. P 167. \n60 Constellation Request for Clarification or Rehearing at 8 (citing Hughes v. Talen \nEnergy Mktg., LLC, 578 U.S. 150, 164-65 (2016); Nantahala Power & Light Co. v. \nThornburg, 476 U.S. 953, 966 (1986)). \n61 Id. \n62 Id.   \n63 Id. at 7 (citing December Order, 193 FERC ¶ 61,217 at P 167). \n64 December Order, 193 FERC ¶ 61,217 at P 167 (emphasis added)."},{"page":22,"startToken":6993,"endToken":7298,"text":"Docket No. EL25-49-002, et al. \n- 22 - \nrates . . . .”65  While Constellation frames its request around the jurisdictional findings in \nthe December Order, Constellation raises a specific matter that is not the subject of and is \notherwise outside the scope of this proceeding, i.e., the terms of transmission security \nagreements.  We nonetheless reiterate that:  (1) Eligible Customers taking transmission \nservice on behalf of Co-Located Load must have the option to take one of three \ntransmission services, i.e., NITS or Interim NITS, FCD transmission service, or NFCD \ntransmission service;66 and (2) while it remains just and reasonable for an Eligible \nCustomer taking transmission service on behalf of Co-Located Load to take NITS \ncharged on a gross demand basis,67 an Eligible Customer may instead choose to take \nanother transmission service.68   \n3. \nRetail BTMG \na. \nDecember Order \n \nIn the December Order, the Commission found that circumstances have changed \nsince the Commission approved PJM’s retail BTMG netting rules such that these rules \nare no longer just and reasonable.  In particular, the Commission found that PJM’s \nexisting retail BTMG netting rules do not limit the amount of qualifying load that a \nNetwork Customer may net by using BTMG and do not provide any protections against \npotential transmission and resource adequacy planning problems or against the costs of \nmaintaining sufficient resources to serve these loads being shifted onto other customers.69  \nThe Commission concluded that PJM’s retail BTMG netting rules are no longer \nconsistent with cost causation principles because large loads configured in a BTMG \narrangement with significant generation will raise cost-shifting concerns compared to \nloads pursuing smaller amounts of netting.70  \n \n65 Hughes v. Talen Energy Mktg., LLC, 578 U.S. 150, 164. \n66 December Order, 193 FERC ¶ 61,217 at P 193. \n67 Id. P 195. \n68 Id. P 199. \n69 Id. P 186. \n70 Id."},{"page":23,"startToken":7298,"endToken":7575,"text":"Docket No. EL25-49-002, et al. \n- 23 - \nb. \nRequest for Clarification and/or Rehearing \n \nIndustrials argue that the Commission failed to explain and justify its assertion of \njurisdiction over “retail BTMG that merely offsets retail load.”71  Industrials contend that \n“retail BTMG [is not within] the Commission’s jurisdiction over the transmission of \nelectric energy in interstate commerce” because “[b]y definition, BTMG is produced by a \ngeneration unit ‘that delivers energy to load without using the Transmission System.’”72  \nIndustrials assert that the Commission’s finding “necessarily entails piercing the retail \nmeter veil, which serves as the bright-line boundary of the Commission’s statutory \nauthority.”73  Industrials further maintain that the Commission failed to provide a                 \nwell-reasoned basis for the assertion of jurisdiction over the configurations of retail \ncustomers whose BTMG is not selling wholesale power and is not using the transmission \nsystem.74  Industrials argue that, here, “retail BTMG involves neither jurisdictional sales \nnor jurisdictional transmission.”75 \nc. \nDetermination \n \nWe disagree with Industrials that the BTMG netting rules are outside of the \nCommission’s jurisdiction.  Industrials misunderstand the December Order as targeting \nretail sales from BTMG or the delivery of energy from BTMG to load, but this is not the \ncase.  The BTMG netting rules instead allow PJM to calculate the charges for \n \n71 Industrials Request for Clarification or Rehearing at 39.  \n72 Id. at 40 (citing PJM, Intra-PJM Tariffs, OATT, § I.1 (Definitions – A-B) \n(22.0.0)). \n73 Id. \n74 Id. at 40-41 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d \n1277, 1280 (D.C. Cir. 2007); Detroit Edison Co. v. FERC, 334 F.3d 48, 53 (D.C. Cir. \n2003)).  \n75 Id. at 41-42."},{"page":24,"startToken":7575,"endToken":7941,"text":"Docket No. EL25-49-002, et al. \n- 24 - \ntransmission service in interstate commerce.76  The calculation of such transmission \ncharges is squarely within the Commission’s jurisdiction under the FPA.77 \n4. \nRetail Backup Service \na. \nDecember Order \n \nIn the December Order, the Commission required that PJM modify its Tariff to \nrequire that an Eligible Customer taking transmission service on behalf of a Co-Located \nLoad take one of three transmission services:  (1) NITS or Interim NITS; (2) FCD \ntransmission service; or (3) NFCD transmission service.78 \nb. \nRequest for Rehearing \n \nExelon and FirstEnergy contend that the Commission’s new FCD and NFCD \ntransmission services infringe on state retail authority, asserting that the states, not the \nCommission, have jurisdiction to decide when and in what circumstances retail load will \nbe curtailed, and how utilities should charge and treat retail customers in those \ncircumstances.79  Exelon and FirstEnergy claim that, for example, states might require the \nprovision of backup service to retail customers who lost supply from their contracted \nsupplier, would regulate the distribution system costs associated with such service that \nwould be charged to the retail customer, and would regulate the costs and terms of the \nbackup service.80  Exelon and FirstEnergy assert that the Commission’s order appears to \ncreate a new federal construct because it defines the extent and terms of backup service to \n \n76 PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the Meter \nGeneration) (0.0.0); see December Order, 193 FERC ¶ 61,217 at P 7 (“[T]he Tariff \nallows load serving entities . . . that provide service to loads with qualifying BTMG to \nreduce their costs by netting output from BTMG in the calculation of their peak demand \nfor the purpose of determining NITS charges.”) (emphasis added). \n77 Orangeburg, 862 F.3d at 1086-87 (“FERC—not state commissions—has \n‘exclusive authority to regulate the transmission . . . of electric energy in interstate \ncommerce.’”) (quoting New Eng. Power Co., 455 U.S. at 340); Calpine Corp. v. FERC, \n702 F.3d 41, 50 (D.C. Cir. 2012) (“[T]he regulation of transmission charges is \nundoubtedly within FERC’s jurisdiction . . . .”). \n78 December Order, 193 FERC ¶ 61,217 at P 193. \n79 Exelon and FirstEnergy Request for Rehearing at 53.  \n80 Id."},{"page":25,"startToken":7941,"endToken":8375,"text":"Docket No. EL25-49-002, et al. \n- 25 - \nretail customers who lose their contracted retail power supplier.81  Exelon and \nFirstEnergy argue that the Commission’s new transmission services lack the limitation in \nthe Commission’s wholesale demand response programs, which allow states to prohibit \nretail consumers from participating in wholesale demand response.82 \nc. \nDetermination \n \nWe are not persuaded by Exelon and FirstEnergy’s assertions that FCD and NFCD \ntransmission services infringe on state retail authority.  In the December Order, the \nCommission held that Eligible Customers taking transmission service on behalf of a              \nCo-Located Load must have the option to take one of three transmission services:  \n(1) NITS or Interim NITS; (2) FCD transmission service; or (3) NFCD transmission \nservice.83  Exelon and FirstEnergy do not explain how FCD and NFCD transmission \nservices define the extent and terms of backup service to retail customers who lose their \ncontracted power supplier and cite no specific aspect of the December Order that does \nso.84  As such, we find that Exelon and FirstEnergy fail to demonstrate that the \nCommission’s replacement rate regulates the terms of retail service.85  \n \n81 Id. at 53, 55. \n82 Id. at 54 (citing FERC v. EPSA, 577 U.S. 260, 275 (2016)). \n83 December Order, 193 FERC ¶ 61,217 at P 193. \n84 FPA section 313(a) requires that an “application for rehearing shall set forth \nspecifically” its grounds. 16 U.S.C. § 825l(a) (emphasis added).  We follow Commission \npractice, with which courts have agreed, and reject arguments, like this one, on rehearing \nlacking sufficient specificity.  PJM Interconnection, L.L.C., 171 FERC ¶ 61,040, at P 22 \n(2020); see also Ind. Util. Regul. Comm’n v. FERC, 668 F.3d 735, 736 (D.C. Cir. 2012); \nLA Storage, LLC, 182 FERC ¶ 61,026, at P 25 & n.75 (2023).   \n85 Exelon and FirstEnergy argue that the Commission’s new transmission services \nlack the limitation in the Commission’s wholesale demand response programs, which \nallows states to prohibit retail consumers from participating in wholesale demand \nresponse.  Exelon and FirstEnergy Request for Rehearing at 54 (citing FERC v. EPSA, \n577 U.S. at 275).  The considerations that led the Commission to include that “opt-out” in \nthe rulemakings that led to Order Nos. 719 and 745, such as a confluence of federal and \nstate jurisdiction with respect to demand response, are not present in this proceeding.  \nMoreover, the Commission was not required to include the “opt-out” even in those \nrulemakings.  See Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 964 F.3d 1177, 1187 \n(D.C. Cir. 2020) (“But because FERC has the exclusive authority to determine who may"},{"page":26,"startToken":8375,"endToken":8699,"text":"Docket No. EL25-49-002, et al. \n- 26 - \nB. \nShow Cause Findings \n1. \nOverview, Transmission Service, Regulation and Black Start \na. \nDecember Order \n \nAs relevant here, the Commission found in the December Order that the Tariff is \nunjust and unreasonable because it does not contain provisions addressing with sufficient \nclarity or consistency the rates, terms, and conditions of service that apply to \nInterconnection Customers serving Co-Located Load and Eligible Customers taking \ntransmission service on behalf of Co-Located Load.  The Commission also found that the \nTariff is unjust and unreasonable because it does not include transmission services that \nreflect Eligible Customers taking service on behalf of Co-Located Loads that are willing \nand able to limit their energy withdrawals from the transmission system under certain \nconditions.86   \nb. \nRequest for Rehearing \n \nExelon and FirstEnergy argue that the Commission did not meet its burden under \nFPA section 206 to show that the existing PJM Tariff is unjust and unreasonable.87  \nExelon and FirstEnergy argue that the Commission provides no evidentiary support for \nits finding that the Tariff is unjust and unreasonable because it does not contain \nprovisions addressing with sufficient clarity or consistency the rates, terms, and \nconditions of service that apply to Interconnection Customers serving Co-Located Load \nand Eligible Customers taking transmission service on behalf of Co-Located Load.88  \nExelon and FirstEnergy allege that the Tariff already has provisions explaining how to \nserve load in PJM and the Commission does not even mention them.89 \n \nExelon and FirstEnergy dispute that the Constellation Complaint supports the \nCommission’s finding of uncertainty.90  Exelon and FirstEnergy contend that the actual \n \nparticipate in the wholesale markets, the Supremacy Clause—not Order No. 841—\nrequires that States not interfere.”). \n86 December Order, 193 FERC ¶ 61,217 at P 177. \n87 Exelon and FirstEnergy Request for Rehearing at 13. \n88 Id. at 14 (citing December Order, 193 FERC ¶ 61,217 at P 175). \n89 Id. at 15 (discussing and citing Tariff provisions). \n90 Id."},{"page":27,"startToken":8699,"endToken":9122,"text":"Docket No. EL25-49-002, et al. \n- 27 - \nsituation described in the Constellation Complaint giving rise to the purposed uncertainty \nrevealed that “any delay resulted from a decision made by Constellation in its attempt to \nbypass retail service requirements and to obtain service in violation of Illinois law.”91  \nExelon and FirstEnergy argue that, if any clarification was necessary, the Commission \nhas now clarified that Co-Location Arrangements must be properly metered and \ndesignate and involve transmission service to an Eligible Customer.  Exelon and \nFirstEnergy allege that service can proceed in an orderly fashion.  Exelon and \nFirstEnergy argue that the Commission ignored record evidence that customers’ load \nservice requests proceed on a timely basis when customers take service through an \nEligible Customer.92  Exelon and FirstEnergy also maintain that Talen Energy’s recent \nchanges to its Co-Location Arrangement with Susquehanna Nuclear, LLC show that the \nTariff works.93 \n \nExelon and FirstEnergy next challenge the Commission’s finding that the Tariff is \nunjust and unreasonable because it does not include transmission services that reflect that \nan Eligible Customer taking service on behalf of a Co-Located Load that is willing and \nable to limit its energy withdrawals from the transmission system under certain \nconditions.94  Exelon and FirstEnergy allege that there is no evidence that the cost of \nNITS deters service or impacts data center development.  Exelon and FirstEnergy also \nargue that there is no evidence to support the Commission’s statement that requiring \nNITS could necessitate inefficient and costly transmission buildout and costs paid by \ntransmission customers that may not be necessary if Eligible Customers taking \ntransmission service on behalf of Co-Located Loads are willing to limit their energy \nwithdrawals and take a transmission service that requires fewer Network Upgrades.95  \nExelon and FirstEnergy maintain that charging load on a contract demand basis does not \nchange the physical and engineering impacts of the load.96  Exelon and FirstEnergy \nacknowledge that installing systems to limit grid usage might change system impacts and \nthe need for upgrades, but there is nothing in the record demonstrating that such systems \nare more beneficial for Co-Located Load than other loads or that such systems warrant \n \n91 Id. at 15-16 (citing Constellation, Docket No. EL25-20-000, Complaint, Ex. 5, \nattach. 1). \n92 Id. at 17. \n93 Id. at 17-18 (citing PJM, Docket No. ER24-2172-000, Amended ISA, attach. A, \nSchedule F, Part F.4 (filed June 3, 2024)). \n94 Id. at 18 (citing December Order, 193 FERC ¶ 61,217 at P 159). \n95 Id. at 19 (citing December Order, 193 FERC ¶ 61,217 at P 199). \n96 Id."},{"page":28,"startToken":9122,"endToken":9542,"text":"Docket No. EL25-49-002, et al. \n- 28 - \nthe use of different ratemaking principles for Co-Located Load as compared to other \nloads.97  Exelon and FirstEnergy argue that system impacts may be reduced when a load \nis located near a generator, but that is true whether the load contracts with remote \ngeneration or an abutting generator.  Exelon and FirstEnergy assert that the study process \ncan determine how to site to reduce transmission upgrades for the customer using the \ncustomer’s gross load.  \n \nExelon and FirstEnergy argue that the Commission provides no support for its \nstatement that Co-Located Loads may be able to receive transmission service faster with \nuse of a new, limited transmission service product than they would if they selected NITS, \nto the extent that providing NITS would require Network Upgrades that the limited \ntransmission service would not.98  Exelon and FirstEnergy assert that the transmission \nsystem is affected even when no net power is withdrawn from the system.99  Exelon and \nFirstEnergy contend that the Commission endorses an unsound approach by suggesting \nthat loads that do not withdraw from the system can be interconnected on a fast track \nwithout studying physical impacts. \n \nExelon and FirstEnergy highlight the Commission’s statement that, while the \nCommission finds that NITS charged on a gross demand basis is one just and reasonable \ntransmission service option for Eligible Customer taking transmission service on behalf \nof Co-Located Loads, it is not the only option.100  Exelon and FirstEnergy state that the \nCommission itself acknowledges that the existing service options are feasible and just \nand reasonable, but the Commission merely wants more options.  Exelon and FirstEnergy \nargue that when the Commission finds a tariff not unjust and unreasonable under the first \nprong of FPA section 206, as it suggests here, the Commission does not need to set a \nremedy.  \n \nExelon and FirstEnergy disagree with the Commission’s assessment that                    \nCo-Located Loads merit a different rate based on the combination of transmission system \nburdens and benefits.  Exelon and FirstEnergy first state that Co-Located Loads benefit \nfrom regulation and black start, as the Commission recognized.101  Exelon and \nFirstEnergy argue that transmission interconnections provide an avenue for data center \nloads to readily acquire back-up power when co-located generators are not available.  \n \n97 Id. at 19-20. \n98 Id. at 20 (citing December Order, 193 FERC ¶ 61,217 at P 205). \n99 Id. at 21. \n100 Id. at 22 (citing December Order, 193 FERC ¶ 61,217 at P 195). \n101 Id. at 30 (citing December Order, 193 FERC ¶ 61,217 at PP 209, 219)."},{"page":29,"startToken":9542,"endToken":9944,"text":"Docket No. EL25-49-002, et al. \n- 29 - \nExelon and FirstEnergy argue that, based solely on these uses of the transmission system, \nCo-Located Loads have no greater claim to preferential rates than other similarly situated \ntransmission customers.  Exelon and FirstEnergy argue that the Commission failed to \nconsider the many advantages to Co-Located Loads when they connect to the \ntransmission system.  For example, Exelon and FirstEnergy assert that, if the project were \nislanded instead of grid connected, all back-up generation would sit idled when not \nneeded, forgoing significant revenues from selling surplus power into the wholesale \nmarket.  Exelon and FirstEnergy also allege that it is very difficult to supply islanded \ngeneration with black start and regulation.102 \n \nExelon and FirstEnergy argue that the Commission failed to respond to arguments \nabout the unique aspects of co-location with nuclear plants.  Exelon and FirstEnergy state \nthat a nuclear facility must be interconnected to the grid as a Nuclear Regulatory \nCommission licensing obligation, and thus a Co-Location Arrangement with a nuclear \nunit depends on the grid.103  Exelon and FirstEnergy assert that, in a Co-Location \nArrangement with a nuclear unit, Co-Located Load depends on services such as \nregulation, voltage support, black start, and other ancillary services delivered over the \ngrid all the time because nuclear units cannot provide these services.104 \nc. \nDetermination \n \nOn rehearing, we sustain the Commission’s finding in the December Order that \nthe Tariff is unjust and unreasonable.105  First, we continue to find that the Tariff does not \ncontain provisions addressing with sufficient clarity or consistency the rates, terms, and \nconditions of service that apply to Interconnection Customers serving Co-Located Load \n \n102 Id. at 31. \n103 Id. at 32-33 (citing Exelon, Docket No. EL25-20-000, Comments, attach. 1,               \n¶¶ 11-13, 16)). \n104 Id. at 32 (citing Exelon, Docket No. EL25-20-000, Comments, attach. 1,                       \n¶¶ 14-19)). \n105 December Order, 193 FERC ¶ 61,217 at PP 175-177.  As discussed in the \nDecember Order, we continue to find the Tariff also unjust and unreasonable in \nadditional related ways—for example, we continue to find that the Tariff is unjust and \nunreasonable because it does not address charges for black start and regulation service to \nEligible Customers taking transmission service on behalf of Co-Located Load.  Id. P 159.  \nWe do not interpret Exelon and FirstEnergy, however, to be disputing this finding.  \nSeparate portions of this order address our findings in this proceeding that additional \naspects of the Tariff are unjust and unreasonable."},{"page":30,"startToken":9944,"endToken":10379,"text":"Docket No. EL25-49-002, et al. \n- 30 - \nand Eligible Customers taking transmission service on behalf of Co-Located Load.106  \nSecond, we continue to find that the Tariff does not include transmission services that \nreflect Eligible Customers taking service on behalf of Co-Located Loads that are willing \nand able to limit their energy withdrawals from the transmission system under certain \nconditions.107 \n \nSubstantial evidence supports the Commission’s finding that the Tariff lacks \nsufficient clarity as to the rules governing Interconnection Customers serving Co-Located \nLoad and Eligible Customers taking transmission service on behalf of Co-Located \nLoad.108  There is significant support in the record for this finding.109  In particular, PJM \nrecognizes that its Tariff lacks sufficient clarity in this area.110  We also find persuasive \nthe comments in the record from a range of stakeholders reflecting the uncertainty facing \nentities seeking to effectuate Co-location Arrangements within PJM.111   \n \n106 Id. P 175.  \n107 Id. P 177.  \n108 Id. PP 175-176. \n109 Id. P 176 n.376. \n110 PJM March 24, 2025 Response at 32 (noting that its “Tariff provisions d[o] not \ncontemplate the type of arrangements at issue in this docket”); id. at 35 (“The extent to \nwhich netting [rules under the Tariff] could . . . apply to co-located data center load is not \nclear at this time.”); see also Vistra April 23, 2025 Reply Comments at 11 (arguing that \nPJM has “effectively conceded” that the Tariff does not contain sufficient clarity). \n111 See Constellation May 8, 2025 Answer at 3-9 (collecting record support and \nconcluding “[i]n sum, the record in this proceeding unequivocally supports the . . . \nfinding that the PJM Tariff lacks clear co-location rules”); AEU April 23, 2025 Reply \nComments at 19 (“Loads and generators pursuing [C]o-[L]ocation [A]rrangements need \nclarity as to how these arrangements will be studied, and how those studies will be \nevaluated.  There must be a level of uniformity and detail outlining study requirements to \nensure regulatory certainty for large loads and new generation and storage resources \nseeking to serve large loads.  This level of uniformity is currently lacking in PJM’s \ninterconnection procedures and cost allocation methodology . . . .”); Electric Power \nSupply Association (EPSA)/PJM Power Providers Group (P3) April 23, 2025 Reply \nComments at 2 (“EPSA and P3 agree with the Commission that PJM needs to establish \ntariff provisions and rules to accommodate the array of [C]o-[L]ocated [L]oad \narrangements that will facilitate the timely and effective integration of large loads \nlocating in the region.”); DCC April 23, 2025 Reply Comments at 7 (“. . . [T]he \nCommission should direct PJM to develop clear, enforceable tariff language that affirms"},{"page":31,"startToken":10379,"endToken":10780,"text":"Docket No. EL25-49-002, et al. \n- 31 - \n \nFurther, there has been significant confusion and dispute over what rules govern \nCo-Location Arrangements in PJM.  As the Commission found in the December Order, \nthe absence of clear tariff provisions creates uncertainty that has resulted in disparate \ntreatment of potential Co-Location Arrangements in PJM, where transmission owners \nhave taken different approaches to performing the necessary steps that apply to \nInterconnection Customers seeking to serve Co-Located Load through a Co-Location \nArrangement, leading to no consistent understanding of entities’ responsibilities with \nrespect to their planned Co-Location Arrangements.112  Further, in 2024, PJM developed \na now-rescinded “Guidance Document,” which included non-binding guidance for \ngenerators and loads seeking to enter into Co-Location Arrangements113—further \nsuggesting that PJM’s existing Tariff did not provide sufficient clarity resulting in a lack \nof consistent understanding among stakeholders.  Indeed, parties have raised varying \ninterpretations of the rules that apply to Co-Location Arrangements across Commission \nproceedings.114 \n \nthe permissibility of multiple co-location configurations, including those where load is \nserved directly from a generation resource located on or near the same site.  Tariff clarity \nis essential to reduce unnecessary disputes, avoid case-by-case confusion, and enable \ntransmission providers to process interconnection and load addition requests efficiently \nand predictably.”). \n112 December Order, 193 FERC ¶ 61,217 at P 175 & n.375 (citing Constellation, \nComplaint, Docket No. EL25-20-000 (filed Nov. 22, 2024); Baltimore Gas & Electric \nCompany and PECO Energy Company, Petition for Declaratory Order, Docket                        \nNo. EL24-149-000 (filed Sept. 30, 2024); Constellation April 23, 2025 Reply Comments \nat 4 n.4).  \n113 PJM, PJM Guidance on Co-Located Load (Mar. 22, 2024) (updated Apr. 17, \n2024), https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/pjm-\nguidance-on-co-located-load.pdf. \n114 For instance, an amended ISA to which PPL was a party stated that “The                  \nCo-Located Load is not Network Load, and it is intended that the Co-Located Load will \nnever consume capacity and/or energy from the PJM Transmission System.”  PJM \nInterconnection, L.L.C. (Susquehanna), Amended Susquehanna ISA, Docket                               \nNo. ER24-2172, Schedule F, Part F (filed June 3, 2024); see also, e.g., PJM \nInterconnection, L.L.C., 189 FERC ¶ 61,078, at PP 14, 26 (2024).  On the other hand, \nthere are allegations in the record that Exelon has delayed work on Constellation’s \nrequests to co-locate load with certain of its generators due to Exelon’s concerns that \nsuch requests are not allowed under the Tariff without arranging for wholesale"},{"page":32,"startToken":10780,"endToken":11147,"text":"Docket No. EL25-49-002, et al. \n- 32 - \n \nIn fact, based on our review of the Tariff, the Tariff indeed does not contain \nprovisions specifying the rules governing Co-Location Arrangements.115  For instance, \nthe Tariff lacks provisions specifying:  the terms and conditions for Interconnection \nCustomers seeking to use their generators to serve Co-Located Load;116 that an \nInterconnection Customer who will use its generator to serve Co-Located Load must \ndesignate an Eligible Customer who will take transmission service on behalf of the                  \nCo-Located Load;117 the rules governing transmission service—including the rates, \nterms, and conditions of that service—taken by an Eligible Customer on behalf of Co-\nLocated Load;118 and the charges for black start and regulation service to Eligible \nCustomers taking transmission service on behalf of Co-Located Load.119  In sum, due to \nthe absence of these provisions, the Tariff lacks sufficiently clear answers to important \nquestions about how to effectuate Co-Location Arrangements.   \n \nThe finding that the Tariff is unjust and unreasonable due to the lack of sufficient \nclarity is bolstered by several factors.  First, the lack of sufficient clarity leaves entities \nunable to determine what steps they can or must take to effectuate or administer                        \nCo-Location Arrangements of various configurations.120  Interconnection Customers \nseeking to use their generators to serve Co-Located Load have no means of knowing their \nresponsibilities with respect to serving Co-Location Arrangements and the terms and \nconditions that apply to these arrangements.121  Without an Eligible Customer designated \nto take transmission service on behalf of a Co-Located Load, the Tariff lacks a \nmechanism to address and ensure proper charges for situations in which a Co-Located \nLoad withdraws energy from the transmission system.122  Second, an absence of \n \ntransmission or retail distribution service.  February Order, 190 FERC ¶ 61,115 at PP 51, \n75. \n115 December Order, 193 FERC ¶ 61,217 at P 175.  \n116 Id. P 176.   \n117 Id.  \n118 Id.; see also, e.g., id. P 175. \n119 Id. P 177; see also id. PP 159, 181-185. \n120 Id. P 175.  \n121 Id. P 176.  \n122 Id.  Indeed, Exelon and FirstEnergy concede that they agree that “[a]n Eligible \nCustomer serving a co-located load must be designated because it is the Eligible"},{"page":33,"startToken":11147,"endToken":11589,"text":"Docket No. EL25-49-002, et al. \n- 33 - \nsufficient clarity in these circumstances creates regulatory uncertainty, thus undermining \na “central purpose” of the FPA—“predictability.”123  Third, the lack of sufficient clarity \nleads here to the potential for undue discrimination, preferential treatment, or otherwise \nunjustifiable disparate conduct.  As discussed above, disparate treatment has occurred in \nPJM, where transmission owners have taken different approaches to addressing                        \nCo-Location Arrangements.124  Finally, the lack of sufficient clarity introduces the risk \nthat costs related to Co-Location Arrangements may not be allocated consistent with cost \ncausation principles because, for instance, Eligible Customers taking transmission service \non behalf of Co-Located Load could benefit from regulation and black start services \nwithout contributing to cost recovery for such services, thus risking that costs may be \nallocated entirely to other transmission customers and passed through to residential \ncustomers, among others.125  In total, these factors are magnified by the facts that                   \nCo-Location Arrangements are becoming increasingly common in PJM, entities continue \nto raise issues involving Co-Location Arrangements with the Commission,126 and                  \nCo-Location Arrangements may include large amounts of load and generation.  Given \nthese ramifications and consistent with precedent,127 the Commission appropriately found \nthat the lack of sufficient clarity in the Tariff has rendered it unjust and unreasonable.  \n \nCustomer that seeks and obtains transmission service and pays for it.”  Exelon and \nFirstEnergy Request for Rehearing at 2.  \n123 PJM Power Providers Grp. v. FERC, 96 F.4th 390, 401-02 (3d Cir. 2024) \n(describing a central purpose of the filed rate doctrine:  predictability).  Ensuring \npredictability ultimately supports a primary purpose of the FPA, “encourag[ing] the \norderly development of plentiful supplies of electricity . . . at reasonable prices.”  Pub. \nUtils. Comm’n of Cal. v. FERC, 367 F.3d 925, 929 (D.C. Cir. 2004) (quoting NAACP v. \nFPC, 425 U.S. 662, 670 (1976); see EPSA, 577 U.S. at 290 (“The statute aims to protect \n‘against excessive prices’ and ensure effective transmission of electric power.” (citations \nomitted)).   \n124 December Order, 193 FERC ¶ 61,217 at P 175; February Order, 190 FERC \n¶ 61,115 at P 75. \n125 December Order, 193 FERC ¶ 61,217 at P 177; see also id. PP 181-185.  \n126 Id. P 4.  \n127 E.g., Invenergy Transmission LLC v. Midcontinent Indep. Sys. Operator, Inc., \n193 FERC ¶ 61,033, at P 53 (2025) (finding tariff unjust and unreasonable because it did \nnot address when and how certain transmission projects are incorporated into a \ntransmission planning model and because existing provisions lacked “sufficient \nspecificity and certainty”); PJM Interconnection, L.L.C., 167 FERC ¶ 61,030, at PP 22, \n41, 59 (2019) (“[W]e find that the PJM Operating Agreement is unjust and unreasonable"},{"page":34,"startToken":11589,"endToken":12008,"text":"Docket No. EL25-49-002, et al. \n- 34 - \n \nNotwithstanding the Commission’s findings, Exelon and FirstEnergy argue that \nbecause the Tariff provides for NITS and point-to-point service (PTPS)—with terms \ngoverning them—“[t]here is no inability to determine how to serve [co-located] load in \nPJM.”128  Yet, the existence of provisions governing NITS and PTPS does not undermine \nour findings that the Tariff both lacks sufficient clarity and does not contain provisions \nspecifying the rules governing Co-Location Arrangements.  The applicability, operation, \nand/or interpretation of the cited general provisions (among others) with respect to \nEligible Customers taking transmission services on behalf of Co-Located Load and                \nCo-Location Arrangements are the issues that, in part, give rise to the lack of sufficient \nclarity we target here.   \n \nNext, Exelon and FirstEnergy respond to the Commission’s citation of the \nConstellation Complaint by blaming “any delay” giving rise to uncertainty on \nConstellation.129  But this response misunderstands the Commission’s reasoning.  The \nCommission cited the Constellation Complaint as one piece of evidence to demonstrate \nthat there is “no consistent understanding” of the rules governing Co-Location \nArrangements.130   \n \nSimilarly, Exelon and FirstEnergy allege that “in 2025, [Commonwealth Edison \nCompany] received more than 25 customer service applications for large load service, \nrepresenting new load in excess of 20 GW” and “[t]here is no suggestion in the record \nthat any customer is encountering problems with those requests.”131  Beyond the fact \nthere is no representation that any of those applications relate to Co-Located Load, this \nlimited set of applications before a single Transmission Owner does not demonstrate \n \nbecause it fails to provide a sufficient level of clarity regarding the permissible \ncomponents of energy market cost-based offers”); N.Y. Indep Sys. Operator, Inc.,                  \n162 FERC ¶ 61,107, at PP 160, 173 (2018) (“We find this difference in definitions to be \nunclear and, therefore, unjust and unreasonable”); Dominion Energy Mktg., Inc., v. ISO \nNew Eng. Inc., 155 FERC ¶ 61,121, at P 17 (2016) (“We find that [the] existing Tariff is \nunclear as to whether new incremental capacity and existing capacity at the same \ngenerating station must submit a composite offer in order to participate in [a capacity \nauction].  As a result of this lack of clarity, the Tariff fails to provide adequate notice of \nwhat the requirement is and, thus, we find the Tariff is unjust and unreasonable.”). \n128 Exelon and FirstEnergy Request for Rehearing at 14-15. \n129 Id. at 15-16. \n130 December Order, 193 FERC ¶ 61,217 at P 175. \n131 Exelon and FirstEnergy Request for Rehearing at 17."},{"page":35,"startToken":12008,"endToken":12413,"text":"Docket No. EL25-49-002, et al. \n- 35 - \nsufficient clarity even if those requests “proceed on a timely basis.”132  As explained \nabove, the Commission continues to be concerned about disparate treatment by different \nTransmission Owners in this context.133 \n \nExelon and FirstEnergy also state that in one proceeding pertaining to Co-Located \nLoad, a load and generator entered into a “front-of-the-meter” arrangement and thus \n“conceded that PJM Network Service works . . . and is a service upon which all \ncustomers may rely.”134  A decision in one proceeding to abandon a Co-Location \nArrangement does not undermine the Commission’s finding that there is a lack of \nsufficient clarity related to Co-Location Arrangements writ large (and, in fact, might \nsupport it).   \n \nFinally, Exelon and FirstEnergy contend that “[t]o the extent clarification was \nneeded, the Commission has now clarified . . . that these arrangements must be properly \nmetered and must designate and involve transmission service to an Eligible Customer.”135  \nThis argument is misplaced.  Exelon and FirstEnergy’s argument that the replacement \nrate should be narrower—that only part of it would be sufficient—should be directed not \nto the finding that the Tariff is unjust and unreasonable but to the determination of a just \nand reasonable replacement rate.  Further, the portions of the replacement rate that \nExelon and FirstEnergy reference—requiring proper metering and involving transmission \nservice to an Eligible Customer—do not resolve the Commission’s concerns as to a lack \nof sufficient clarity in the Tariff.  For example, the Commission found a lack of sufficient \nclarity as to the terms and conditions for Interconnection Customers seeking to use their \ngenerators to serve Co-Located Load.136  \n \nWe also continue to find that the Tariff is unjust and unreasonable because it does \nnot include transmission services that reflect Eligible Customers taking service on behalf \nof Co-Located Loads that are willing and able to limit their energy withdrawals from the \ntransmission system under certain conditions.137  Requiring Eligible Customers taking \n \n132 Id. \n133 See supra notes 114, 126. \n134 Exelon and FirstEnergy Request for Rehearing at 17-18 (discussing the \nproceedings in Docket Nos. ER24-2172-000 and ER24-2171-001).  \n135 Id. at 16-17.  \n136 December Order, 193 FERC ¶ 61,217 at P 176. \n137 Id. P 177; see also S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 64-68 (D.C. \nCir. 2014) (explaining that to find a practice unjust and unreasonable, the Commission \nneed not rely on “empirical evidence” and can rely on “reasonable economic"},{"page":36,"startToken":12413,"endToken":12878,"text":"Docket No. EL25-49-002, et al. \n- 36 - \ntransmission service on behalf of Co-Located Load to take NITS, without the option to \ninstead take such alternative transmission services, is economically inefficient.  Here, the \nrecord demonstrates that some Eligible Customers taking service on behalf of                      \nCo-Located Loads are willing and able to limit their energy withdrawals.  With only the \ncurrent services offered, having found that Eligible Customers taking NITS will be \ncharged based on gross load, prospective Eligible Customers taking transmission service \non behalf of Co-Located Load would have to take a transmission service that does not \nreflect the load’s willingness and ability to limit use of the transmission system—which \nis an inefficient result.  The Commission has long recognized that providing \ndifferentiated service options can produce more efficient results because customers can \nchoose the service that is most closely tailored to their specific needs, rather than a             \none-service-fits-all approach.138  Requiring Eligible Customers taking service on behalf \nof Co-Located Loads to take NITS creates an unacceptable risk of more costly Network \nUpgrades that would be unnecessary if such Eligible Customers were willing and \npermitted to take a transmission service that reflects Co-Located Loads that are willing \n \npropositions” “likely enough to be within the Commission’s authority” and noting that \nthe use of words such as “might, may, or could” does not make its determination legally \ndeficient (internal quotation marks omitted)). \n138 See, e.g., Integration of Variable Energy Res., Order No. 764, 139 FERC \n¶ 61,246, at PP 2, 22, order on reh’g & clarification, Order No. 764-A, 141 FERC                    \n¶ 61,232 (2012), order on clarification & reh’g, Order No. 764-B, 144 FERC ¶ 61,222 \n(2013) (explaining that the Commission sought “to provide all transmission customers \nthe option of using more frequent transmission scheduling intervals within each operating \nhour, at 15-minute intervals,” which will allow them “the flexibility to adjust their \ntransmission schedules, thus limiting their exposure to imbalance charges” and lead to \n“more efficient utilization of transmission and generation resources”); Standardization of \nGenerator Interconnection Agreements & Procs., Order No. 2003, 104 FERC ¶ 61,103 \n(2003), order on reh’g, Order No. 2003-A, 106 FERC ¶ 61,220, at P 534, order on reh’g, \nOrder No. 2003-B, 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003-C,                \n111 FERC ¶ 61,401 (2005), aff’d sub nom. Nat’l Ass’n of Regul. Util. Comm’rs v. FERC,            \n475 F.3d 1277 (D.C. Cir. 2007) (explaining that “an Interconnection Customer that elects \nto be studied for Network Resource Interconnection Service has the option also to be \nstudied for Energy Resource Interconnection Service and proceed with Network \nResource Interconnection Service or a lower level Interconnection Service whereby only \ncertain Network Upgrades will be completed” and finding that “[t]his option thus allows \nthe Interconnection Customer to avoid having to fund Network Upgrades that it does not \nneed”)."},{"page":37,"startToken":12878,"endToken":13314,"text":"Docket No. EL25-49-002, et al. \n- 37 - \nand able to limit their energy withdrawals.139  We further reiterate that there is support in \nthe record for the foregoing analysis.140 \n \nOn rehearing, Exelon and FirstEnergy dispute the Commission’s finding that the \nTariff is unjust and unreasonable because it does not include transmission services that \nreflect Eligible Customers taking transmission service on behalf of Co-Located Loads \nthat are willing and able to limit their energy withdrawals from the transmission system \nunder certain conditions.141  First, Exelon and FirstEnergy argue that “there is no \nevidence that the cost of paying for Network Service deters service or has any impact \nwhatsoever on development of data centers” because “data center development interest in \nPJM is overwhelming.”142  But the Commission was not required to show that its FPA \nsection 206 step one findings would have a particular effect on data centers.  Instead, as \nexplained in the prior paragraph, the Commission’s findings relate to economic and other \nharms from a lack of transmission services that reflect Eligible Customers taking service \non behalf of Co-Located Loads that are willing and able to limit their energy withdrawals \nfrom the transmission system.143  In any event, we continue to reason that requiring \nEligible Customers taking transmission service on behalf of Co-Located Load to take \nNITS does have a negative impact relative to transmission services that reflect these \nloads’ willingness and ability to limit energy withdrawals.  These negative impacts could \ninclude unnecessary Network Upgrade costs, which cause an unjust and unreasonable \nincrease in transmission rates.  The assertion that “development interest” in data centers \nmay currently be high, or will remain high if Eligible Customers taking transmission \nservice on behalf of Co-Located Loads that are willing and able to limit their withdrawals \nfrom the transmission system are required to take NITS on a gross basis, does not address \nthe counterfactual at issue (i.e., requiring Eligible Customers taking transmission service \non behalf of Co-Located Load to take NITS relative to transmission services that reflect \nthese loads’ willingness and ability to limit energy withdrawals).  \n \nSecond, Exelon and FirstEnergy contend that the Commission has no evidence144 \nto support the risk of “costly and inefficient transmission system buildout” under NITS \n \n139 December Order, 193 FERC ¶ 61,217 at PP 177, 199, 205.  \n140 Id. PP 199 & n.423, 205, 434; see also PP 160, 177-178.  \n141 Exelon and FirstEnergy Request for Rehearing at 18. \n142 Id. at 18-19.  \n143 December Order, 193 FERC ¶ 61,217 at P 177. \n144 Exelon and FirstEnergy Request for Rehearing at 19-20 (citing, among other \nthings, December Order, 193 FERC ¶ 61,217 at P 199)."},{"page":38,"startToken":13314,"endToken":13793,"text":"Docket No. EL25-49-002, et al. \n- 38 - \ncompared to “fewer Network Upgrades” and “lower Network Upgrade costs” under an \nalternative service.145  To the contrary, the Commission has provided a robust rationale \nfor this risk, as explained above.  Exelon and FirstEnergy state that “network studies are \nbased on physics and engineering” so NITS cannot “impose[] unnecessary transmission \nupgrade costs.”146  We agree with the premise that studies are based on physics and \nengineering, but not the conclusion.  Many Network Upgrades are caused by the amount \nof MW flow on the transmission system but certain Network Upgrades are not (e.g., they \nmay be caused by stability or voltage-related issues).147  Therefore, as Exelon and \nFirstEnergy concede, under a transmission service designed to reflect load’s willingness \nand ability to limit energy withdrawals, “if the load installs systems aimed at limiting its \nuse of the grid, those might change the system impacts and need for upgrades.”148  \nConversely, NITS requires PJM to plan the transmission system to deliver power to \nload,149 even if that load does not intend to ever withdraw power from the system, which \ncould result in unnecessary Network Upgrades.  Exelon and FirstEnergy also claim that \n“[t]he fact that a load is located near a generator may well reduce system impacts . . . \n \n145 December Order, 193 FERC ¶ 61,217 at P 177. \n146 Exelon and FirstEnergy Request for Rehearing at 19. \n147 Exelon and FirstEnergy additionally contend that “even when no net power is \nbeing withdrawn from the system . . . the transmission system is affected and needed by \nthe load—indeed, the Commission agreed with this proposition when it found that co-\nlocated loads do utilize load-following based on gross rather than net load.”  Id. at 19-21.  \nAgain, we do not find that the need for Network Upgrades is based only on withdrawals; \ninstead, we find that reducing the amount of MW flow can lead to the need for fewer or \nless costly Network Upgrades.  The December Order does not promote ignoring impacts \nwhen no net power is being withdrawn. \n148 Id. at 19-20.  We note that Exelon and FirstEnergy also state that “the same can \nbe said for similar systems applied to other loads.  Nothing in the record [supports] that \nsuch systems are more beneficial for co-located load projects than for any other load [or] \nthe use of different ratemaking principles when such installations are in place.  To the \ncontrary, . . . the Commission has consistently rejected arguments that different \nratemaking should be applied even where there are physical limits to the amount of \ntransmission system use.”  Id.  We understand these arguments as directed to the \nreplacement rate, and thus we address them below.  To the extent they are directed to the \nCommission’s FPA section 206 step one finding, we disagree for the same reasons stated \nbelow. \n149 PJM, Intra-PJM Tariffs, OATT, § III, § 28.2 (Transmission Provider \nResponsibilities) (1.0.0)."},{"page":39,"startToken":13793,"endToken":14239,"text":"Docket No. EL25-49-002, et al. \n- 39 - \nregardless of whether the load has contracted with the generator it abuts, or with remote \ngeneration.”150  This assertion ignores the fact that a new transmission service reflecting \nwillingness and ability to limit energy withdrawals could further reduce system \nimpacts—for instance through the “systems aimed at limiting [the] use of the grid” that \nExelon and FirstEnergy reference.151  We similarly disagree with Exelon and \nFirstEnergy’s claim that a new transmission service would not “alter what must be \nstudied in assessing the physics and engineering of any proposed new configuration.”152  \nStudies for a customer taking a new transmission service that limits the amount of energy \nthat may be withdrawn would reflect that limitation.153  Such potential transmission \nservice could alter the level of steady-state transmission system usage studied (i.e., the \n“physics”) and the design of the physical facilities, necessary control technologies, and/or \nprotection systems needed to effectuate that arrangement compared to a traditional \nNetwork Customer (i.e., the “engineering”), contrary to Exelon and FirstEnergy’s \nassertions. \n \nThird, Exelon and FirstEnergy assert that the Commission contradicted itself in \nfinding the Tariff unjust and unreasonable in lacking alternative transmission services \nbecause the Commission also stated that “‘it continues to be just and reasonable for an \nEligible Customer taking transmission service on behalf of Co-Located Load to elect, as \none of the required transmission services from which the Eligible Customer must choose, \nto take NITS.’”154  The Commission did not find that current set of transmission service \noptions is just and reasonable.  Instead, the Commission stated, it continues to be just and \nreasonable for such an Eligible Customer “to elect” NITS “as one of the required \n \n150 Exelon and FirstEnergy Request for Rehearing at 20. \n151 Id. at 19-20.  Exelon and FirstEnergy likewise claim that Co-Location \nArrangements “will have the same potential benefit regardless of whether there is a \ncontractual supply arrangement with a nearby generator and regardless of whether it pays \nfor transmission service based on net or gross load.”  Id. at 21.  This assertion again \nmisses the key distinction.  Under a new alternative transmission service reflecting \nwillingness and ability to limit energy withdrawals, there could be fewer or less costly \nNetwork Upgrades if the Eligible Customer can select a lower (but otherwise \nsatisfactory) level of demand. \n152 Id. at 20. \n153 Exelon and FirstEnergy state that “[t]here is simply no evidence” for an \nargument that a new transmission service could speed access to service.  Id.  But the \nCommission’s findings are not based on speeding access to service or creating “fast-track \ninterconnection.”  Id. at 20-21. \n154 Id. at 21-22 (quoting December Order, 193 FERC ¶ 61,217 at P 195)."},{"page":40,"startToken":14239,"endToken":14644,"text":"Docket No. EL25-49-002, et al. \n- 40 - \ntransmission services.”155  But it is unjust and unreasonable for that set of options to lack \nthe alternatives the Commission discussed.156  \n \nFourth, Exelon and FirstEnergy argue that the Commission’s finding that the \nTariff is unjust and unreasonable because it lacks alternative transmission service options \nmisunderstands the benefits and burdens “to co-located projects of being interconnected \nto the grid.”157  The Commission did not find, however, that Co-Located Loads could \nreceive no benefits from or place no burdens on the transmission system.  Instead, the \nCommission found that the Tariff was unjust and unreasonable because it did not reflect \nthe features of Co-Location Arrangements that make the existing transmission service \noptions unacceptable.158  An Eligible Customer taking transmission service on behalf of \nCo-Located Load must be charged for the benefits received from and the burdens placed \non the transmission system—but that does not mean the status quo is not unjust and \nunreasonable.  Co-Located Load may be able to reduce the benefits received from and the \nburdens placed on the transmission system if it is willing and able to limit energy \nwithdrawals.  We do not dispute, and indeed continue to find, that Co-Located Loads do \nreceive benefits even if they have zero net energy withdrawals, specifically from \nregulation and black start services.159  The Commission’s finding that the Tariff is unjust \nand unreasonable does not preclude the recognition of those benefits. \n \nFinally, Exelon and FirstEnergy maintain that the Commission’s “finding that the \nexisting PJM Tariff is [unjust and unreasonable] is arbitrary and capricious because the \nCommission failed to consider the unique issues that attend co-location with nuclear \nplants.”160  This argument is misplaced.  The Commission found that the Tariff is unjust \nand unreasonable for, in part, the two reasons discussed above.161  In particular, the \nCommission found the Tariff unjust and unreasonable because it does not include an \noption for Eligible Customers on behalf of Co-Located Loads to take transmission \nservices that reflect their willingness and ability to limit their energy withdrawals from \n \n155 December Order, 193 FERC ¶ 61,217 at P 195 (emphasis added). \n156 Id. P 177.  \n157 Exelon and FirstEnergy Request for Rehearing at 30-32; see also id. \n(discussing various benefits and burdens).  \n158 December Order, 193 FERC ¶ 61,217 at P 177.  \n159 Id. P 185. \n160 Exelon and FirstEnergy Request for Rehearing at 32-33.  \n161 December Order, 193 FERC ¶ 61,217 at PP 176, 177."},{"page":41,"startToken":14644,"endToken":15029,"text":"Docket No. EL25-49-002, et al. \n- 41 - \nthe transmission system.  The fact that a nuclear generator in a Co-Location Arrangement \nmight be dependent on the transmission system because that nuclear generator cannot \noperate without a robust interconnection to the transmission system, or cannot load \nfollow, does not undermine these core findings.  Exelon and FirstEnergy attempt to use \nthese facts to conclude that the Co-Located Load is effectively using the transmission \nsystem in a similar manner to a load served by remote resources.  We disagree because, \nregardless of load following, the energy used by the Co-Located Load is provided (at \nleast in part) by its Co-Located Generator, not via the transmission system.  Eligible \nCustomers on behalf of Co-Located Loads that are served by a Co-Located Generator \nthat is a nuclear generator should be permitted to take transmission services that reflect \nthat they are willing and able to limit their withdrawals from the transmission system \nunder certain conditions.  To the extent a nuclear generator that is part of a Co-Location \nArrangement operates differently than other Co-Located Generators, that is an issue that \nmay be assessed in subsequent study processes, or simply by the nuclear generator itself, \nas the Interconnection Customer (not the Eligible Customer) in determining whether and \nhow to enter into a Co-Location Arrangement.  \n2. \nRetail BTMG Netting Rules \na. \nScope and Adequate Notice \ni. \nDecember Order \n \nThe Commission found that PJM’s retail BTMG netting rules are no longer just \nand reasonable and clarified that this finding applies to all Network Load.162 \nii. \nRequest for Clarification and/or Rehearing \n \nCiting the Administrative Procedure Act (APA) and Commission Rule 209, \nIndustrials argue that changes to retail BTMG netting rules are outside the scope of the \nFebruary Order.163  Industrials assert that the February Order set the scope of the \nproceeding and limited it to Co-Located Load and Co-Location Arrangements, thus \nexcluding BTMG.  Industrials argue that no part of the February Order included the \npossibility of the Commission’s BTMG netting findings in the December Order.  \nIndustrials allege there are important distinctions between Co-Location Arrangements \nand BTMG, particularly that a BTMG arrangement is a retail load-modification \n \n162 Id. P 186. \n163 Industrials Request for Clarification or Rehearing at 22 (citing 5 U.S.C. § 706; \n18 C.F.R. § 385.209 (2025)); see also 5 U.S.C. § 554."},{"page":42,"startToken":15029,"endToken":15364,"text":"Docket No. EL25-49-002, et al. \n- 42 - \nconstruct, whereas a Co-Location Arrangement is a wholesale-system-impacting load \nintegration construct.164  \niii. \nDetermination \n \nWe disagree with Industrials that changes to retail BTMG netting rules are beyond \nthe scope of this proceeding because the Commission provided adequate notice as to \nthose changes.   \n \nUnder the APA, an agency setting a matter for hearing must provide parties with \nadequate notice of the issues that would be considered, and ultimately resolved, at that \nhearing.165  Under Commission Rule 209(b), “an order to show cause will contain a \nstatement of the matters about which the Commission is inquiring, and a statement of the \nauthority under which the Commission is acting.  The statement is tentative and sets forth \nissues to be considered by the Commission.”166   \n \nWhile Industrials allege that the Commission in the February Order “set the scope \nof the proceeding to Co-Located Load,”167 the Commission did no such thing.  The \nFebruary Order contains no finding limiting the proceeding’s scope to “Co-Located \nLoad.”  Instead, the February Order also expressly raises, among many other topics, \nrelevant generation configurations168 and overall addresses issues that attend to load with \non-site or otherwise nearby generation, which logically includes BTMG.169   \n \n164 Industrials Request for Clarification or Rehearing at 22-26.  \n165 N. Va. Elec. Coop., Inc. v. FERC, 945 F.3d 1201, 1205 (D.C. Cir. 2019); \n5 U.S.C. § 554(b)(3) (establishing notice requirement for adjudications). \n166 18 C.F.R. § 385.209(b). \n167 Industrials Request for Clarification or Rehearing at 22.  \n168 February Order, 190 FERC ¶ 61,115 at P 79.  \n169 Id. P 76 (discussing concerns related to generation and load being “likely to use \nor benefit from the transmission system in different ways depending on how they are \nconfigured” and giving examples such as “Network Load may co-locate with a generator \nthat is not a grid resource and that either serves the load as an off-grid backup or that \nreduces the Network Load’s consumption during peak hours” (emphasis added))."},{"page":43,"startToken":15364,"endToken":15783,"text":"Docket No. EL25-49-002, et al. \n- 43 - \n \nIn any event, Industrials themselves acknowledge that the Commission’s briefing \nquestions in fact specifically included BTMG.170  In particular, the Commission asked \nparties to address “how co-located loads are similar to or disparate from other types of \narrangements where load and generation share the same point of interconnection (such as \nBehind the Meter Generation[)].”171  This question reflects that the Commission would \nconsider BTMG configurations in determining a just and reasonable replacement rate.  \nIndustrials contend that the Commission’s reference to “other arrangements” in this \nquestion shows that retail BTMG and Co-Located Load are distinct concepts, but \nIndustrials’ claims are belied by their assertions in their reply comments to the February \nOrder that BTMG configurations and Co-Location Arrangements identically impact the \ntransmission system.172  And regardless of their similarity, the Commission’s briefing \nquestion raises the subject of the treatment of BTMG.  Additional briefing questions in \nthe February Order also sufficiently raise the subject of BTMG.  The Commission \ndirected parties to submit briefing on transmission services, including potential changes \nto the rates, terms, and conditions of NITS to accommodate Co-Location \nArrangements.173  PJM’s retail BTMG netting rules are part of PJM’s rates, terms, and \nconditions for NITS.174  Finally, the Commission also asked “whether portions of the \nGuidance Document may serve as a just and reasonable and not unduly discriminatory or \npreferential replacement rate,”175 and that document states, “[i]f the co-located Customer \nFacility elects to be designated as [BTMG], it will be allowed to net the co-located load \ndirectly against the output of the co-located Customer Facility.”176  We thus find that the \nFebruary Order provided adequate notice that the Commission would consider PJM’s \nBTMG netting rules as part of this proceeding. \n \nThe record developed in response to the February Order further reflects that \nIndustrials had notice and an opportunity to address changing PJM’s retail BTMG netting \n \n170 Industrials Request for Clarification or Rehearing at 25. \n171 February Order, 190 FERC ¶ 61,115 at P 88 (briefing question a.iv). \n172 PJM ICC and IECA April 23, 2025 Reply Comments at 9. \n173 February Order, 190 FERC ¶ 61,115 at P 88 (briefing question b.iv). \n174 PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the Meter \nGeneration) (0.0.0). \n175 February Order, 190 FERC ¶ 61,115 at P 88 (briefing question a.iii). \n176 PJM, PJM Guidance on Co-Located Load (Mar. 22, 2024) (updated Apr. 17, \n2024), https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/pjm-\nguidance-on-co-located-load.pdf."},{"page":44,"startToken":15783,"endToken":16215,"text":"Docket No. EL25-49-002, et al. \n- 44 - \nrules.  While Industrials attempt to minimize the briefing questions as “scarcely \nmention[ing]” BTMG among a large number of topics in the February Order, PJM \nsubmitted detailed concerns that the retail BTMG netting rules were no longer just and \nreasonable in direct response to the February Order.177  And parties debated the merits of \nPJM’s concerns in reply comments.178  All parties, including Industrials, had an \nopportunity to rebut PJM’s claims before the Commission could weigh the evidence on \nthis matter.  As courts have explained, subsequent briefing on a topic serves as evidence \nof adequate notice as to that topic.179  \nb. \nWhether PJM’s Retail BTMG Rules Are Unjust and \nUnreasonable \ni. \nDecember Order \n \nIn finding that PJM’s retail BTMG netting rules are no longer just and reasonable, \nthe Commission explained that circumstances had changed since the Commission \napproved PJM’s rules in 2004.180  The Commission stated that PJM explains that the \nBTMG netting rules were “conceived for, and [have] been implemented for, substantially \nsmaller loads (like a warehouse with solar panels) and not on the scale of large data \n \n177 PJM March 24, 2025 Response at 34 (“The co-located load arrangements at \nissue here, large data centers, could be viewed as similar to BTM Generation that \ncurrently exists under PJM’s Tariff (as reflected in Ex. A, Option 3).  But as explained \nherein, the BTM Generation paradigm does not fit co-location arrangements particularly \nwell because it was not designed with large load co-location in mind.”); id. at 36-37 (“In \nsum, discussions in the record regarding PJM’s BTM Generation rules raise questions \nabout the status of those rules.  PJM is open to exploring . . . whether the 20-year-old \nmethod of allocating costs pursuant to the BTM Generation netting rules remains \nconsistent with cost causation principles.”). \n178 Compare AMP April 23, 2025 Reply Comments at 10 (“The record provides \nno basis to revisit the current PJM Tariff provisions addressing BTMG.”), with \nNortheastern Rural Electric Membership Corporation (NREMC) April 23, 2025 Reply \nComments at 5 (“Additionally, simple netting of generation against load could allow \nthese facilities [i.e., data centers] to avoid most, if not all, costs by netting out to zero as \nthe entire load is supplied by the co-located generator, despite the co-located loads \nreliance and benefit from the grid.  This would shift costs and burdens unfairly to other \nusers, violating core principles of just and reasonable ratemaking.”). \n179 N. Va. Elec. Coop., Inc., 945 F.3d at 1206. \n180 December Order, 193 FERC ¶ 61,217 at P 186 (citing PJM, 107 FERC \n¶ 61,113 (2004) (2004 BTMG Order))."},{"page":45,"startToken":16215,"endToken":16656,"text":"Docket No. EL25-49-002, et al. \n- 45 - \ncenters.”181  However, the Commission stated that large loads, both existing and in the \nplanning stages with PJM, have proliferated in recent years, and PJM has persuasively \nexplained the problems that could occur if Network Customers with large loads were \nallowed to use the existing BTMG netting rules in the Tariff.182  The Commission stated \nthat, for example, PJM explains that “[a]llowing very large loads like data centers to net \nis problematic because loads in this configuration do not carry reserves.”183  The \nCommission stated that such loads must nevertheless be served, however, allowing them \nto “lean on the PJM system when the [BTMG] is on a full or partial outage or if the load \nexceeds the rating of the [BTMG].”184  The Commission emphasized that PJM’s existing \nBTMG netting rules do not limit the amount of qualifying load that a Network Customer \nmay net by using BTMG and do not provide any protections against this potential \ntransmission and resource adequacy planning problem or against the costs of maintaining \nsufficient resources to serve these loads being shifted onto other customers.185  The \nCommission found that PJM’s BTMG netting rules are no longer consistent with cost \ncausation principles, because large loads configured in a BTMG arrangement with \nsignificant generation will raise cost-shifting concerns compared to loads pursuing \nsmaller amounts of netting.  The Commission found that PJM’s existing BTMG netting \nrules may lead to both reliability and resource adequacy risks because PJM, per its Tariff, \nis obligated to serve transmission customers using BTMG but does not consider such \ncustomers in transmission and resource adequacy planning. \nii. \nRequest for Clarification and/or Rehearing \n \nIndustrials argue that the Commission erred by failing to address prior precedent \non cost causation and failing to demonstrate that the existing BTMG netting rules were \n \n181 Id. (quoting PJM March 24, 2025 Response at 13). \n182 Id. (citing Docket No. AD24-11-000, Large Loads Co-Located at Generating \nFacilities Tr. at 9:2-3 (noting that “large data centers [] need these significant new \namounts of energy for their business”); PJM Interconnection, L.L.C., 188 FERC                        \n¶ 61,200, at P 5 (2024) (“PJM explains that the [tariff] proposal [to allocate load \nadjustments] was spurred by the recent proliferation of data centers that are contributing \nto large additions of forecasted load concentrated within a specific wholesale metering \narea.”)). \n183 December Order, 193 FERC ¶ 61,217 at P 186 (quoting PJM March 24, 2025 \nResponse at 36). \n184 Id. (quoting PJM March 24, 2025 Response at 13 n.5). \n185 Id. (citing PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the \nMeter Generation) (0.0.0))."},{"page":46,"startToken":16656,"endToken":17074,"text":"Docket No. EL25-49-002, et al. \n- 46 - \nunjust and unreasonable.186  Industrials contend that Commission precedent established \nthe “actual use” principle, which holds that “actual use” of the transmission system is a \njust and reasonable approach for assessing transmission charges that comports with cost \ncausation.187  Industrials argue that the Commission here abandons the “actual use” \nprinciple by finding BTMG netting unjust and unreasonable.188  According to Industrials, \nthe December Order also “creates an unreasonable split between those who manage costs \nby managing load and those who manage costs by investing in generation.”189  “In other \nwords,” Industrials contend, “the effect of the ‘gross load’ approach is unduly \ndiscriminatory, because it allows ‘actual use’ to govern NITS costs for some (i.e.,                 \nload-only customers), but not for others (i.e., those who have invested in retail                  \nbehind-the-meter generation).”190  Industrials acknowledge that “[i]f standby fees or other \ncharges need to be considered in accordance with cost-causation principles, the \nCommission may explore those,” but argue that “eliminating altogether the assessment of \ncharges based on ‘actual use’ is unduly discriminatory and fails to reckon with                    \nwell-established Commission precedent.”191  \n \n186 Industrials Request for Clarification or Rehearing at 34; see also id. at 5, 19-20. \n187 Id. at 35-36 (citing 2004 BTMG Order, 107 FERC ¶ 61,113, at P 4 (finding “no \ntransmission or distribution facilities are used to deliver energy from the generating unit \nto the load”); Occidental Chem. Corp. v. PJM Interconnection, 102 FERC ¶ 61,275,                    \nat P 14 (2003) (Occidental) (“Access charges for use of PJM’s transmission system \nshould be allocated to network customers based on a network customer’s actual use of \nPJM’s system, consistent with the principle of cost causation.”); PJM Interconnection, \nL.L.C., 167 FERC ¶ 61,268, at P 23 (2019) (PJM) (affirming Commission’s conclusion in \nOccidental that Network Customers’ charges for use of PJM’s transmission system \nshould be allocated based on a Network Customer’s actual use of PJM’s system); ISO \nNew Eng., Inc., 178 FERC ¶ 61,086, at P 51 (2022) (ISO-NE) (finding just and \nreasonable ISO New England Inc.’s proposal to exclude from the Monthly Regional \nNetwork Load served by unregistered BTMG and the portion of the output of a Generator \nAsset that serves load located behind the same retail customer meter and assign Regional \nNetwork Service charges to Network Customers based on each Network Customer’s \nactual use of the system)). \n188 Industrials Request for Clarification or Rehearing at 35-37.  \n189 Id. at 37.  \n190 Id. at 37-38. \n191 Id. at 38."},{"page":47,"startToken":17074,"endToken":17491,"text":"Docket No. EL25-49-002, et al. \n- 47 - \n \nIndustrials argue that the Commission did not develop a sufficient record on which \nto base its determinations on BTMG netting rules in the Tariff.192  Industrials give several \nexamples of “real-life facility configurations” that will face substantial harms or be \nundercompensated under a “gross load” approach.193  Industrials argue that, without a \nwell-developed record, the Commission may not be able to fully recognize the cost \ncausation implications of the removal of all netting rules. \niii. \nDetermination \n \nWe disagree with Industrials that the Commission failed to address prior precedent \nin the December Order or show that PJM’s retail BTMG netting rules were unjust and \nunreasonable.194  The Commission in the December Order summarized its decision \napproving PJM’s retail BTMG netting rules, including the finding in the 2004 BTMG \nOrder accepting the BTMG netting rules that “charges for use of PJM’s transmission \nsystem should be allocated to network customers based on a network customer’s actual \nuse of PJM’s system, consistent with the principle of cost causation.”195  We recognize \nthat the Commission’s 2004 BTMG Order relied upon Occidental for the proposition that \nNITS charges should be based on actual use,196 and that, after 2004, the Commission has \nrelied upon Occidental and/or the 2004 BTMG Order to support similar findings.197  But \nthe Commission in the December Order did not find that it is no longer just and \nunreasonable to ever allocate transmission charges based on actual use.  Rather, the \nCommission found that PJM’s retail BTMG netting rules are no longer consistent with \ncost causation principles for a specific reason, that is, because large loads configured in a \nBTMG arrangement with significant generation will raise cost-shifting concerns \n \n192 Id. at 26; see also id. at 6. \n193 Id. at 27-31; see also id. at 4-5. \n194 Id. at 34-38. \n195 December Order, 193 FERC ¶ 61,217 at P 7 (quoting 2004 BTMG Order,                   \n107 FERC ¶ 61,113 at P 28); Id. P 186 (citing 2004 BTMG Order, 107 FERC ¶ 61,113). \n196 2004 BTMG Order, 107 FERC ¶ 61,113 at P 28 (citing Occidental, 102 FERC \n¶ 61,275). \n197 See PJM, 167 FERC ¶ 61,268 at P 23 (discussing Occidental for the \nproposition that the Commission has found that RTOs and transmission owners must \nrecognize load reductions from interruptible load programs in computing billing \ndeterminants); ISO-NE, 178 FERC ¶ 61,086 at P 51 (finding just and reasonable ISO \nNew England’s proposal to charge Network Customers based on actual use of the \nsystem)."},{"page":48,"startToken":17491,"endToken":17917,"text":"Docket No. EL25-49-002, et al. \n- 48 - \ncompared to loads pursuing smaller amounts of netting.198  The Commission thus \nexplained that these PJM retail BTMG netting rules, while previously consistent with \ncost causation principles at the time the Commission approved them, were rendered \nunjust and unreasonable by a change in circumstances.  In further support of its finding \nthat these rules are no longer just and reasonable, the Commission found that PJM’s \nexisting retail BTMG netting rules may lead to both reliability and resource adequacy \nrisks because PJM, per its Tariff, is obligated to serve transmission customers using \nBTMG but does not consider such customers in transmission and resource adequacy \nplanning.199  The Commission orders relying on actual use principles that Industrials cite \ndo not reflect the problems currently posed in PJM by large loads configured in a BTMG \narrangement.200   \n \nWe also disagree with Industrials that the Commission did not develop a sufficient \nrecord on which to base its determination in the December Order on PJM’s retail BTMG \nnetting rules.201  As discussed above, the Commission adequately supported its findings \nthat PJM’s retail BTMG netting rules are no longer just and reasonable.  Importantly, the \nCommission relied on evidence submitted by PJM detailing problems that could occur if \nNetwork Customers with large loads were allowed to use the existing retail BTMG \nnetting rules in the Tariff.202  Other parties raised similar concerns in the record.203 \n \nIndustrials instead raise concerns that the Commission’s decision results in \nsignificant economic harm to entities who have used PJM’s retail BTMG netting rules \n \n198 December Order, 193 FERC ¶ 61,217 at P 186. \n199 Id.; see PJM, Intra-PJM Tariffs, OATT, § III, § 34.2 (Netting of Behind the \nMeter Generation) (0.0.0). \n200 See, e.g., ISO-NE, 178 FERC ¶ 61,086 at P 8 (explaining that, decades ago, \nbehind-the-meter generation was typically larger on-site generation connected to \nindustrial load, but since then, behind-the-meter generation has evolved with increasing \namounts of widely distributed behind-the-meter generation that is below 5 MW, such as \nsolar photovoltaic generation). \n201 Industrials Request for Clarification or Rehearing at 26-27. \n202 December Order, 193 FERC ¶ 61,217 at P 186 (“For example, PJM explains \nthat “[a]llowing very large loads like data centers to net is problematic because loads in \nthis configuration do not carry reserves.”) (quoting PJM March 24, 2025 Response at 36). \n203 Id. P 73 (“NREMC argues that large Co-Located Loads paired with BTMG \npresent significantly greater operational risks than traditional BTMG arrangements \nbecause they lack adequate reserves.”) (citing NREMC April 23 Reply Comments at 5)."},{"page":49,"startToken":17917,"endToken":18373,"text":"Docket No. EL25-49-002, et al. \n- 49 - \nand the Commission may not have fully recognized the cost causation implications of the \nremoval of all netting rules.204  We find these concerns unpersuasive for several reasons.  \nFirst, we believe Industrials’ argument concerns how the Commission fashions a \nreplacement rate that determines the extent to which entities may be able to continue to \nrely on netting,205 not to the Commission’s finding that the existing rate in PJM is no \nlonger just and reasonable.   \n \nSecond, as the Commission explained in the December Order in its determination \non transmission services, NITS charges based on gross load for Network Load are \nroughly commensurate with the benefits received because Network Load has the right to \nbe served from the transmission system at any time.206  The Commission’s decision to \nrevise PJM’s retail BTMG netting rules may increase transmission charges for Network \nCustomers who have used PJM’s retail BTMG netting rules, but this change better aligns \nthe benefits and costs for these customers and addresses cost-shifting concerns because it \nreflects the fact that they must be served even when their retail BTMG is on outage.207  \n \nThird, as discussed elsewhere in this order, we set aside the December Order in \npart and permit Eligible Customers taking transmission service on behalf of load served \nby BTMG to have the option to take the new transmission services set forth in the \nDecember Order.  Therefore, Eligible Customers taking transmission service on behalf of \nload served by BTMG will, at minimum, not be required to take NITS on a gross load \nbasis but will have the option to take and be charged for different transmission services.   \n \nFourth, we note that Industrials offer six examples involving specific BTMG \narrangements that could be financially harmed by the removal of PJM’s retail BTMG \nnetting rules.  As discussed above, to the extent these BTMG arrangements are \nfinancially harmed, that implicates the Commission’s decision to set a replacement rate \nas to the extent to which such entities may continue to net going forward.  Also, as \ndiscussed below, we set aside the December Order in part and direct PJM to exempt \ncertain cogeneration facilities from revised retail BTMG netting rules where the facilities \nmay be integrated with load such that, when their generator trips offline, the load follows \n(rather than withdrawing energy from the transmission system), as such facilities would \nnot present the cost shift, reliability, or resource adequacy concerns discussed in the \n \n204 Industrials Request for Clarification or Rehearing at 27. \n205 See supra Part IV.C.1.c. \n206 December Order, 193 FERC ¶ 61,217 at P 198. \n207 See id. P 186 (finding that PJM’s retail BTMG netting rules raise cost-shifting \nconcerns due to large loads configured in BTMG arrangements)."},{"page":50,"startToken":18373,"endToken":18709,"text":"Docket No. EL25-49-002, et al. \n- 50 - \nDecember Order.208  To the extent that any of the facilities discussed in Industrials’ six \nexamples could demonstrate that they do not present such concerns, they may fall within \nthe exemption that we direct PJM to submit as part of the compliance filing discussed \nbelow.209   \n \nWe also disagree with Industrials that the December Order unduly discriminates \nagainst Network Customers who manage costs by investing in generation as compared to \nNetwork Customers who manage costs by managing load.  Undue discrimination \nprohibited by the FPA can occur when similarly situated customers are treated \ndifferently.210  Here, Industrials fail to show that the December Order results in \ndifferential treatment because Network Customers are subject to charges for NITS based \non gross load whether or not they have associated generation, with the exception of the \nmateriality threshold for retail BTMG discussed below.  In addition, the December Order \nneither addresses nor limits Network Customers’ ability to manage load, whether or not \nthey have associated generation. \n3. \nTransmission Service Options for BTMG \na. \nDecember Order \n \nAs explained above, the Commission found that the Tariff is unjust and \nunreasonable because it does not include transmission services that reflect Eligible \nCustomers taking service on behalf of Co-Located Loads that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions.211   \n \nThe Commission found that PJM’s retail BTMG netting rules were no longer just \nand reasonable, explaining that these rules may lead to both reliability and resource \nadequacy risks because PJM, per its Tariff, is obligated to serve transmission customers \n \n208 Id. \n209 See, e.g., Industrials Request for Clarification or Rehearing at 27 (“Because the \nmanufacturing process requires steam produced for generation, the bulk of the load can \nremain online only if generation is operational.  If the generation goes down, the load will \nlargely cease as well.”). \n210 Cal. Indep. Sys. Operator Corp., 193 FERC ¶ 61,117, at P 33 (2025). \n211 December Order, 193 FERC ¶ 61,217 at P 193."},{"page":51,"startToken":18709,"endToken":19071,"text":"Docket No. EL25-49-002, et al. \n- 51 - \nusing BTMG but does not consider such customers in transmission and resource \nadequacy planning.212   \nb. \nRequest for Clarification and/or Rehearing \n \nIndustrials request clarification that the new transmission services must be made \navailable to Eligible Customers taking transmission service on behalf of load-only \ncustomers with BTMG.213  Industrials argue that Eligible Customers taking transmission \nservice on behalf of load-only customers with BTMG should also be allowed to benefit \nfrom the new transmission services.214 \nc. \nDetermination \n \nWe set aside, in part, the December Order.  In addition to the finding in the \nDecember Order that the Tariff is unjust and unreasonable as to Eligible Customers \ntaking transmission service on behalf of Co-Located Load, we also find that the Tariff is \nunjust and unreasonable because it does not include transmission services that reflect that \nEligible Customers taking transmission service on behalf of load with BTMG are willing \nand able to limit their energy withdrawals from the transmission system under certain \nconditions.  Requiring Eligible Customers taking transmission service on behalf of load \nwith BTMG to take NITS, without the option to instead take such alternative \ntransmission services that reflect their willingness and ability to limit their energy \nwithdrawals, would be unjust and unreasonable for the same reasons we made the same \nfinding with respect to Eligible Customers taking transmission service on behalf of                \nCo-Located Load.215  For purposes of this order, then, we use the term Eligible Load to \nrefer to Co-Located Load216 and/or load with BTMG.217  We also direct PJM to file, \nwithin 60 days of the date of issuance of this order, a definition for Eligible Load, or \nother comparable Tariff revisions to implement these directives, and to revise its \ndefinition of BTMG to allow Eligible Customers taking transmission service on behalf of \n \n212 Id. P 186. \n213 Industrials Request for Clarification or Rehearing at 13-14.  \n214 Id.  \n215 See supra Part IV.B.1.c (discussing further the Commission’s finding in the \nDecember Order that the Tariff is unjust and unreasonable as to Eligible Customers \ntaking transmission service on behalf of Co-Located Load). \n216 See supra P 10. \n217 See supra note 4."},{"page":52,"startToken":19071,"endToken":19424,"text":"Docket No. EL25-49-002, et al. \n- 52 - \nload with BTMG that are willing and able to limit their energy withdrawals from the \ntransmission system under certain conditions to take the new transmission services, \nconsistent with this order.  All Eligible Customers taking one of the new transmission \nservices on behalf of Eligible Load will be subject to the requirements discussed below, \nincluding, but not limited to, operational requirements such as necessary control \ntechnologies and/or protection systems as discussed in part VI.C and penalty charges and \nother remedial actions as discussed in part VI.D. \nC. \nReplacement Rate \n1. \nTransmission Services \na. \nNITS \ni. \nDecember Order \n \nAs relevant here, the Commission found that NITS must be taken on a gross \nbasis.218   \nii. \nRequest for Clarification \n \nPIOs request clarification of the December Order regarding cost allocation issues.  \nPIOs argue that, given the unprecedented volume and scale of large load requests, the \nCommission should evaluate whether existing transmission rate designs remain just and \nreasonable.  PIOs state that the Commission held in the December Order that Co-Located \nLoad taking NITS would be responsible for costs that are “roughly commensurate” with \nbenefits because zonal NITS rates include upgrades and operations and maintenance \ncosts.  PIOs argue that this rate design relies on a standard assuming that load growth is \nincremental and widely distributed, however, whereas discrete large-load pockets trigger \nmulti-million dollar reliability solutions.219   \n \nPIOs contend that a significant “payer gap” can emerge because customers pay \nonly in proportion to billing determinants rather than by the incremental costs that they \ntrigger.  PIOs provide the example of a transmission project portfolio approved in the \n2024 Regional Transmission Expansion Plan (RTEP) Window 1 that will cost           \n$5.08 billion and state that if a 1,000 MW data center represents 7% of the zone’s peak \ndeterminants, it would contribute only $203 million and leave a $4.877 billion gap for \nunrelated regional and zonal customers to pay.  PIOs therefore request that the \nCommission clarify how “roughly commensurate” cost allocation is evaluated when a \n \n218 December Order, 193 FERC ¶ 61,217 at P 195.  \n219 PIOs Request for Clarification at 7."},{"page":53,"startToken":19424,"endToken":19810,"text":"Docket No. EL25-49-002, et al. \n- 53 - \ndiscrete driver’s pro-rata contribution is minimal compared to the infrastructure it \nnecessitates.  PIOs also argue that the Commission should require PJM and the PJM \ntransmission owners to provide transparent reporting for major projects that compares \nincremental cost causation against pro-rata billing determinant recovery.220 \niii. \nDetermination \n \nWe deny the request for clarification.221  In the December Order, the Commission \nfound that NITS must be taken on a gross basis.222  The Commission did not address cost \nallocation for Network Upgrades needed to accommodate NITS (or related reporting \nrequirements) and we decline to do so here, finding those issues to be sufficiently distinct \nfrom the immediate issues in this proceeding and outside the scope of this proceeding.  In \nany event, we note that these issues would be better addressed in a separate proceeding in \nwhich a record could be developed on these technical topics.223 \nb. \nNew Transmission Services \n \nIn the December Order, the Commission—having found the Tariff unjust and \nunreasonable because it lacked relevant provisions with sufficient clarity and \ntransmission services that reflect Eligible Customers taking service on behalf of                  \nCo-Located Loads that are willing and able to limit their energy withdrawals—addressed \na just and reasonable replacement rate.224 \n \n220 Id. at 7-8. \n221 PIOs’ request for clarification is titled and presented as a request for \nclarification, id. at 1, and we treat it as such, noting that it does not meet the \nCommission’s requirements for requests for rehearing.  18 C.F.R. § 385.713(c)(2); Pub. \nServ. Co. of Colo., 190 FERC ¶ 61,128, at P 24 (2025).   \n222 December Order, 193 FERC ¶ 61,217 at P 195.  \n223 See Mobil Oil Expl. & Prod. Serv. v. United Distrib. Cos., 498 U.S. 211,               \n230-31 (1991) (“An agency enjoys broad discretion in determining how best to handle \nrelated, yet discrete, issues in terms of procedures.”); Tenn. Valley Mun. Gas Ass’n v. \nFERC, 140 F.3d 1085, 1088 (D.C. Cir. 1998) (the Commission has “broad discretion to \ndetermine when and how to hear and decide the matters that come before it”); Stowers \nOil & Gas Co., 27 FERC ¶ 61,001, at 61,001 (1984) (“The Commission, like other \nagencies, is generally master of its own calendar and procedures.”). \n224 December Order, 193 FERC ¶ 61,217 at P 193."},{"page":54,"startToken":19810,"endToken":20166,"text":"Docket No. EL25-49-002, et al. \n- 54 - \n \nThe Commission directed PJM to submit a compliance filing to modify its Tariff \nto require that the Eligible Customer taking transmission service on behalf of a                       \nCo-Located Load takes one of three transmission services:  (1) NITS or Interim NITS,  \n(2) a new FCD transmission service, or (3) a new NFCD transmission service.225  The \nCommission also established paper hearing procedures to determine the appropriate rates, \nterms, and conditions of the new transmission services.226  The Commission stated that \nInterim NITS is a new interim, non-firm transmission service, which allows an Eligible \nCustomer that has requested NITS on behalf of a Co-Located Load to take non-firm \ntransmission service that can be interrupted until the Network Upgrades necessary to \nprovide NITS are complete and the Co-Located Load can be designated as Network \nLoad.227   \n \nThe Commission stated that, under the FCD transmission service, Eligible \nCustomers will have the right to request transmission service on behalf of a Co-Located \nLoad up to a specified MW quantity, i.e., the contract demand.  The Commission stated \nthat the FCD transmission service will have the same reservation and curtailment priority \nas existing firm transmission services, at the level of the contract demand.  However, the \nCommission stated that, unlike Network Customers, the Eligible Customer taking the \nFCD transmission service on behalf of the Co-Located Load is not permitted to withdraw \nenergy from the PJM transmission system beyond the contract demand level.228   \n \nThe Commission stated that the new NFCD transmission service will be provided \nduring normal operations, on an as-available basis, and curtailed during emergency \noperations (i.e., it will be curtailed before existing firm transmission services and the new \nFCD transmission service).  The Commission stated that, under this service, Eligible \nCustomers may reserve transmission service on behalf of a Co-Located Load as needed \nduring normal, non-emergency system operating conditions.  The Commission stated that \nreservations under this service would be available only when there is available \ntransmission capacity, similar to existing non-firm transmission service options in the \nTariff.229 \n \n225 Id. \n226 Id. P 194. \n227 Id. P 200. \n228 Id. P 208. \n229 Id. P 215."},{"page":55,"startToken":20166,"endToken":20543,"text":"Docket No. EL25-49-002, et al. \n- 55 - \ni. \nBTMG \n(a) \nRequests for Clarification and/or Rehearing \n As to a replacement rate covering Eligible Customers taking transmission service \non behalf of load-only customers with BTMG, Industrials request clarification that the \nnew transmission services must be made available to those customers.230  Industrials \nargue that Eligible Customers taking transmission service on behalf of load-only \ncustomers with BTMG should also be allowed to benefit from the new transmission \nservices.231   \n(b) \nDetermination \n As explained above, we set aside, in part, the December Order and find that the \nTariff is unjust and unreasonable because it does not include transmission services that \nreflect Eligible Customers taking transmission service on behalf of loads with BTMG that \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions.  Consistent with this new determination, we now direct PJM to revise \nits Tariff to extend the three new transmission services set forth in the December Order to \nEligible Customers taking service on behalf of load with BTMG that are willing and able \nto limit their energy withdrawals from the transmission system under certain conditions. \n Specifically, we direct PJM to submit a compliance filing, within 60 days of the \ndate of this order, to modify its Tariff to require that the Eligible Customer taking \ntransmission service on behalf of Eligible Load takes one of three transmission services:  \n(1) NITS or Interim NITS, (2) FCD transmission service, or (3) NFCD transmission \nservice.232  We find that it is just and reasonable for an Eligible Customer taking \ntransmission service on behalf of Eligible Load to elect, as one of the required \ntransmission services from which the Eligible Customer must choose, to take NITS for \nthe same reasons we made that finding with respect to Eligible Customers taking \ntransmission service on behalf of Co-Located Loads.233 \n Eligible Customers, on behalf of the Eligible Loads that they represent, may \nchoose the transmission services that match their preferred use of the transmission \n \n230 Industrials Request for Clarification or Rehearing at 13-14.  \n231 Id.  \n232 They must choose at least one of the required transmission services and may \ntake a combination of the FCD and NFCD transmission services. \n233 December Order, 193 FERC ¶ 61,217 at PP 195, 198."},{"page":56,"startToken":20543,"endToken":20925,"text":"Docket No. EL25-49-002, et al. \n- 56 - \nsystem; however, they must choose at least one of the required transmission services, and \nmay take a combination of the FCD and NFCD transmission services.  In addition, in \ninstances where load with BTMG includes necessary control technologies and/or \nprotection systems that limit its energy withdrawals, we find that it is a just and \nreasonable replacement rate to allow an Eligible Customer taking transmission service on \nbehalf of Eligible Load to take and be charged for new types of transmission service that \nare alternatives, and not equivalent, to NITS:  FCD and NFCD transmission services.234   \nii. \nUndue Discrimination \n(a) \nRequests for Clarification and/or Rehearing \n Exelon and FirstEnergy argue that the Commission granted an undue preference to \nCo-Located Loads in requiring new forms for transmission services.235  Exelon and \nFirstEnergy charge that the Commission failed “to explain why system protection \nschemes installed in [non-Co-Located Load] configurations would not provide similar \nbenefits and be deserving of preferential rates.”236  Exelon and FirstEnergy contend that \nthe totality of the burdens and benefits of grid interconnection justify charging                       \nCo-Located Load the same rate as all other transmission customers.  Exelon and \nFirstEnergy assert that the Commission’s new transmission service reduces the share of \nembedded costs for Co-Located Loads compared to all other users who receive the same \nbenefits.   \n Industrials request clarification that the new transmission services must be made \navailable to load-only customers with load flexibility, minimal retail BTMG, or no retail \nBTMG.237  Industrials contend that this clarification would reduce the risk of undue \ndiscrimination because “[m]any large load customers can curtail their load at key times \nand control the amount of transmission service they use and when they use it.”238  \nIndustrials also argue that this clarification would avoid potential cost shifts that would \noccur if similarly situated customers were given different options depending only on \nwhether they have small generators on site.  Industrials assert that this clarification would \n \n234 See id. P 205. \n235 Exelon and FirstEnergy Request for Rehearing at 36-39. \n236 Id. at 38. \n237 Industrials Request for Clarification or Rehearing at 13 (“Such an approach \nwould align with the natural gas industry’s long history of large gas consumers electing \nhow much service they purchase.”); see also id. at 6-7.  \n238 Id. at 14."},{"page":57,"startToken":20925,"endToken":21324,"text":"Docket No. EL25-49-002, et al. \n- 57 - \nextend the optionality of the new transmission services to retail BTMG and load-only \ncustomers.239  Lastly, Industrials argue that this clarification could make the PJM \ntransmission planning process more efficient.240   \n(b) \nDetermination \n As an initial matter, we dismiss the argument that the new transmission services \nwould be unduly discriminatory or preferential.241  First, we dismiss this argument for \nlack of finality.  Rule 713(b) of the Commission’s Rules of Practice and Procedure \npermits requests for rehearing “of any final decision or other final order in a \nproceeding.”242  A final decision is one that imposes an obligation, denies a right, or fixes \nsome legal relationship as a consummation of the administrative process.243  The \nDecember Order did not make a final decision on the rates, terms, and conditions for the \nnew transmission services.244  Instead, the Commission found that “additional record \nevidence is needed” and set these issues for paper hearing procedures.245  Setting a matter \n \n239 Id. at 14-15. \n240 Id. at 15.  \n241 Exelon and FirstEnergy Rehearing Request at 19-20, 30-31, 36-39, 52-53; \nIndustrials Request for Clarification or Rehearing at 13-14.  Further, as discussed above, \nwe set aside the December Order, in part, and find in this order that it is just and \nreasonable for Eligible Customers taking transmission service on behalf of load with \nBTMG to take one of three transmission services:  (1) NITS or Interim NITS, (2) FCD \ntransmission service, or (3) NFCD transmission service.  We therefore do not address \nwhether it would be unduly discriminatory or preferential if the replacement rate were to \nnot allow Eligible Customers taking transmission service on behalf of load with BTMG \nto take those services. \n242 18 C.F.R. § 385.713(b); see also 16 U.S.C. § 825l(a) (stating that parties \n“aggrieved by an order issued by the Commission in a proceeding . . . may apply for a \nrehearing within thirty days after the issuance of such order”). \n243 Reliable Automatic Sprinkler Co., Inc. v. Consumer Prod. Safety Comm’n,           \n324 F.3d 726, 731 (D.C. Cir. 2003) (“Final agency action ‘mark[s] the consummation of \nthe agency’s decision making process’ and is ‘one by which rights or obligations have \nbeen determined, or from which legal consequences will flow’”) (quoting Bennett v. \nSpear, 520 U.S. 154, 178 (1997)). \n244 December Order, 193 FERC ¶ 61,217 at P 219. \n245 Id."},{"page":58,"startToken":21324,"endToken":21824,"text":"Docket No. EL25-49-002, et al. \n- 58 - \nfor paper briefing “is interlocutory:  it constitutes a procedural step that does not impose \nan obligation, deny a right, or fix some legal relationship as a consummation of the \nadministrative process.”246  Without a final decision on the rates, terms, and conditions \nfor the new transmission services, it is “premature” to argue or evaluate on rehearing \nwhether those as-yet-undeveloped services would be unduly discriminatory.247  At \nbottom, “the claimed harms are based on speculation regarding potential action that the \nCommission could take, rather than any action the Commission has actually taken.”248  \nAccordingly, because Commission action is not final and is to be succeeded by further \nCommission action, we dismiss the undue discrimination argument.249 \n In any event, we also dismiss the undue discrimination argument for the \nindependent reason that it is outside the scope of this proceeding.  This proceeding \naddresses Eligible Customers taking transmission service on behalf of Eligible Load with \nassociated generation, such as through Co-Location Arrangements and BTMG \n \n246 Algonquin Gas Transmission, LLC, 175 FERC ¶ 61,150, at PP 1, 5-8 (2021); \nsee also Kan. Elec. Power Coop., Inc., 181 FERC ¶ 61,017, at P 10 (2022) (finding that, \nbecause “the Commission found that its preliminary analysis indicated that the Formal \nChallenge and Complaint raised issues of material fact that could not be resolved on the \nrecord before the Commission and are more appropriately addressed in hearing and \nsettlement judge procedures,” “here, Commission action is not final and is to be \nsucceeded by further Commission action,” thus “a request for rehearing may be \ndismissed”); City of Hamilton, Ohio, 82 FERC ¶ 61,349, at 62,359 (1998) (“Setting this \nmatter for a trial-type hearing does not impose an obligation, deny a right, or fix some \nlegal relationship as a consummation of the administrative process.”). \n247 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8; see also, e.g., F.T.C. \nv. Standard Oil Co. of Cal., 449 U.S. 232, 244 n.11 (1980) (Standard Oil) (explaining the \nfact that a “challenge may be mooted in adjudication warrants the requirement that \n[party] pursue adjudication, not shortcut it”); MediNatura, Inc. v. Food & Drug Admin., \n998 F.3d 931, 939 (D.C. Cir. 2021); CSX Transp., Inc. v. Surface Transp. Bd., 774 F.3d \n25, 30 (D.C. Cir. 2014) (explaining that it is a “good sign” that action is non-final when \nfurther agency processes may eliminate need for review).  \n248 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. \n249 See, e.g., Cove Mountain Solar, LLC, 179 FERC ¶ 61,179, at P 7 (2022) \n(dismissing, in part, rehearing request on finality grounds because the Commission had \nestablished hearing and settlement judge procedures); Westlands Transmission, LLC,              \n177 FERC ¶ 61,175, at P 4 (2021); BridgeTex Pipeline Co., LLC, 164 FERC ¶ 61,111,            \nat PP 10-12 (2018); Pac. Gas & Elec. Co., 162 FERC ¶ 61,246, at PP 6-7 (2018); Talen \nEnergy Mktg., LLC, 158 FERC ¶ 61,077, at PP 3-4 (2017)."},{"page":59,"startToken":21824,"endToken":22261,"text":"Docket No. EL25-49-002, et al. \n- 59 - \narrangements.250  In an order issued concurrently, the Commission is initiating a separate \nshow cause proceeding in Docket No. EL26-67-000 to address, among other things, \nwhether the Tariff remains just and reasonable and not unduly discriminatory or \npreferential without provisions addressing transmission services that reflect flexible large \nloads251 that are willing and able to limit their energy withdrawals from the transmission \nsystem under certain conditions.  Accordingly, it is beyond the scope of this \nproceeding—and within the scope of the separate proceeding—to argue that the new \ntransmission services should be extended to Eligible Customers taking transmission \nservice on behalf of flexible large loads.  We thus dismiss this argument as outside the \nscope of this proceeding.252  The Supreme Court has made clear that the Commission \n“enjoys broad discretion in determining how best to handle related, yet discrete, issues in \nterms of procedures.”253  The Supreme Court has “expressly approved a[] . . . \nCommission decision to treat [an] issue separately where a different proceeding would \ngenerate more appropriate information and where the agency was addressing the \nquestion”254—as is true as to the other proceeding.  As courts have further recognized, \n“[w]hile the statute requires the Commission to act upon a finding that rates . . . are unjust \nor unreasonable, it nowhere mandates that having made such a finding with respect to a \ndiscrete issue, the Commission must reopen and reevaluate all other aspects of the filed \nrate.”255  Here, while the Commission addresses Co-Location Arrangements and BTMG, \nthose findings do not necessitate that the Commission reevaluate transmission services \nthat Eligible Customers take on behalf of other types of load.256 \n \n250 See, e.g., December Order, 193 FERC ¶ 61,217 at P 2. \n251 Flexible large loads are a subset of large loads that are not co-located with \ngeneration but that are willing and able to limit their use of the transmission system under \ncertain conditions.  \n252 See PJM Interconnection, L.L.C., 126 FERC ¶ 61,030, at P 16 (2009); see also \nLa. Pub. Serv. Comm’n v. Entergy Corp., 169 FERC ¶ 61,179, at P 9 (2019); N.Y. Indep. \nSys. Operator, Inc., 127 FERC ¶ 61,042, at P 26 (2009); Union Elec. Co., 113 FERC \n¶ 61,320, at P 8 (2005); Cal. Indep. Sys. Operator Corp., 113 FERC ¶ 61,133, at P 24 \n(2005). \n253 Mobil Oil, 498 U.S. at 230-31; see supra note 226. \n254 Mobil Oil, 498 U.S. at 230-31.  \n255 Colo. Off. of Consumer Couns. v. FERC, 490 F.3d 954, 956 (D.C. Cir. 2007). \n256 Industrials Request for Clarification or Rehearing at 6-7, 13-14."},{"page":60,"startToken":22261,"endToken":22715,"text":"Docket No. EL25-49-002, et al. \n- 60 - \n In any event, while we dismiss the undue discrimination argument for the reasons \nexplained above, we address the argument below to provide clarification to the parties.  \nAs relevant here, Industrials argue that it is unduly discriminatory for “load-only \ncustomers with load flexibility” to not be eligible for the new transmission services.257  \nIndustrials contend this creates undue discrimination “between customers with generation \nand customers without generation,” who Industrials state “can curtail their load at key \ntimes and control the amount of transmission service they use and when they use it.”258  \nWe refer in this subsection to these “load-only customers with load flexibility,” as \ndescribed by Industrials, as “flexible loads.” \n The Commission “has wide discretion to determine what constitutes undue \ndiscrimination.”259  Discrimination is undue when there is a difference in rates or terms \nbetween similarly situated entities that is not justified by some legitimate factor.260  \n“[D]istinct operating characteristics” can render entities not similarly situated.261  Here, a \nrelevant distinct operating characteristic is that Eligible Load has an associated generator \n(Co-Located Generator or BTMG) as part of the Co-Location Arrangement or load \nconfigured with BTMG, and flexible load does not.  The presence of these associated \ngenerators is a material factor in analyzing eligibility for the new transmission services.  \nWe anticipate, based on the record here, that Eligible Customers taking transmission \n \n257 Id. at 13-14. \n258 Id.  More generally, Industrials argue that the new transmission services should \nbe extended to all transmission customers.  Id.  Because we dismiss the undue \ndiscrimination argument as nonfinal and outside of scope, we need not address the \nargument that the new transmission services should be extended to all transmission \ncustomers (an even broader, and thus less similar, category).  Moreover, we have, in the \nDecember Order and in this order, sufficiently discussed eligibility for the new \ntransmission services, including by explaining that it is not unduly discriminatory to limit \nthe new transmission services to Eligible Customers taking transmission service on \nbehalf of Eligible Load, such that we need not further address extending the services to \nall transmission customers. \n259 Mo. River Energy Servs. v. FERC, 918 F.3d 954, 958 (D.C. Cir. 2019) (citation \nmodified).  For purposes of the undue discrimination analysis in this order, when we refer \nto Eligible Customers taking transmission service on behalf of Eligible Load as not \nsimilarly situated to Eligible Customers taking transmission service on behalf of flexible \nload, we are referring to Eligible Customers only insofar as they take transmission \nservice on behalf of specific Eligible Loads or flexible loads. \n260 Sw. Power Pool, Inc., 192 FERC ¶ 61,058, at P 175 (2025). \n261 Sw. Power Pool, Inc., 193 FERC ¶ 61,198, at P 82 (2025)."},{"page":61,"startToken":22715,"endToken":23183,"text":"Docket No. EL25-49-002, et al. \n- 61 - \nservices on behalf of Eligible Loads would rely regularly in whole or in part on their \nassociated generators, not on the transmission system, while Eligible Customers taking \ntransmission services on behalf of flexible loads generally would rely entirely on the \ntransmission system, even as they sometimes shift the amount of energy they take.  This \ndynamic creates different transmission system usage, which is relevant to transmission \nservices, charges, and planning.262 \niii. \nContract Demand  \n(a) \nRequest for Rehearing \n Exelon and FirstEnergy argue that the Commission has departed from decades of \nprecedent that NITS is based on the entire gross load of the Network Customer, and the \nCommission failed to adequately explain its departure.263  Exelon and FirstEnergy \nhighlight, for example, the Commission’s statement that it would be inconsistent with \ncost causation principles to require Eligible Customers taking transmission service on \nbehalf of Co-Located Loads that limit their energy withdrawals to take NITS on a gross \ndemand basis.264  Exelon and FirstEnergy allege that the Commission recognized that \n \n262 For the reasons in this Part, we also reject Industrials’ request for clarification \non this issue.  Industrials Request for Clarification or Rehearing at 13-14.   \n263 Exelon and FirstEnergy Request for Rehearing at 22-26 (citing Nat’l R.R. \nPassenger Corp. v. PPL Elec. Utils. Corp., 173 FERC ¶ 61,043 (2020) (Amtrak); Fla. \nPower & Light, 113 FERC ¶ 61,290 (2005), order on reh’g, 116 FERC ¶ 61,012 (2006), \naff’d, 264 F. App’x 4 (D.C. Cir. 2008) (Florida Power & Light); Idaho Power Co.,      \n106 FERC ¶ 61,329 (2004) (Idaho Power); Ameren Servs. Co. v. Prairieland Energy Inc., \n131 FERC ¶ 61,125 (2010) (Ameren); Ariz. Pub. Serv. Co., 151 FERC ¶ 61,191 (2015) \n(APS); Preventing Undue Discrimination & Preference in Transmission Serv., Order            \nNo. 890, 118 FERC ¶ 61,119, order on reh’g, Order No. 890-A, 121 FERC ¶ 61,297 \n(2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, \nOrder No. 890-C, 126 FERC ¶ 61,228, order on clarification, Order No. 890-D,                  \n129 FERC ¶ 61,126 (2009); Promoting Wholesale Competition Through Open Access                           \nNon-Discriminatory Transmission Servs. by Pub. Utils.; Recovery of Stranded Costs by \nPub. Utils. & Transmitting Utils., Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996) \n(cross-referenced at 75 FERC ¶ 61,080), order on reh’g, Order No. 888-A, FERC Stats. \n& Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh’g, Order                \nNo. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC           \n¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Pol’y Study Grp. v. \nFERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. N.Y. v. FERC, 535 U.S. 1 (2002). \n264 Exelon and FirstEnergy Request for Rehearing at 28 (citing December Order, \n193 FERC ¶ 61,217 at P 199)."},{"page":62,"startToken":23183,"endToken":23595,"text":"Docket No. EL25-49-002, et al. \n- 62 - \nthese customers use the transmission system for some services, such as regulation and \nblack start, but for the customer not to use the system for other services makes the \ncustomer partially integrated, contrary to Order No. 888-A.265  Exelon and FirstEnergy \ncontend that the Commission has consistently rejected attempts to create a new third type \nof transmission service by parties whose reasons are exactly the same as the reasons the \nCommission used to justify its decision to establish Contract Demand transmission \nservice based on net load, such as the notion that Co-Located Loads impose less burden \non the grid.  Exelon and FirstEnergy argue that the assessment of NITS is not based on \nactual use, that Network Customers pay the full rate but NITS charges are allocated based \non contribution to system peak.266  Exelon and FirstEnergy contend that Network Load \nneeds to be able to call on service regardless of actual usage and utilities have an \nobligation to serve that load. \n(b) \nDetermination \n We continue to find that it is just and reasonable to charge for FCD and NFCD \ntransmission services based on the contract demand.267  We disagree with Exelon and \nFirstEnergy’s arguments that the Commission erred in not requiring the new FCD and \nNFCD transmission services be charged on a gross load basis and that this decision \nviolates precedent.268  As an initial matter, Exelon and FirstEnergy appear to suggest that \nthe charges for these services would be based “on actual use” or “on net . . . load.”269  As \nexplained in the December Order, however, transmission customers taking the new FCD \nor NFCD transmission service would “be charged based on their contract demand \nirrespective of usage.”270  We continue to find that this is a just and reasonable alignment \nof costs and benefits.271  In particular, for the new FCD transmission service, because \ntransmission customers taking this service would agree to limit withdrawals to the \n \n265 Id. at 24. \n266 Id. at 26-29 (citing Indicated TOs June 3, 2025 Answer, Powers Decl.). \n267 December Order, 193 FERC ¶ 61,217 at P 2. \n268 Exelon and FirstEnergy Request for Rehearing at 22-30. \n269 Id. \n270 December Order, 193 FERC ¶ 61,217 at PP 211, 216 (“Eligible Customers \ntaking the [NFCD] transmission service on behalf of Co-Located Loads will be charged \nfor transmission and ancillary services on an as-reserved contract demand basis, based on \nthe reserved contract demand amount of transmission service (except as noted[)].”).   \n271 Id."},{"page":63,"startToken":23595,"endToken":24027,"text":"Docket No. EL25-49-002, et al. \n- 63 - \ncontract demand through the mandatory implementation of necessary control \ntechnologies and/or protection systems, PJM would only plan the transmission system, \nprocure generation capacity, and be obligated to provide transmission service up to that \ncontract demand.272  Similarly, for the new NFCD transmission service, PJM would only \nbe obligated to provide transmission service up to the reserved contract demand when \nthere is sufficient available transmission capacity to provide the requested service.273  If \nthe transmission customers taking the new FCD and NFCD transmission services were \ncharged for that service on a gross load basis, they could be charged for more load than \nPJM is obligated to plan for, procure generation capacity for, or otherwise serve when \ntransmission capacity is available.  And—because these customers would be charged \nbased on their contract demand irrespective of usage—they would be unable to avoid \nload-ratio cost responsibility by modifying their load at a particular time.274  \n Exelon and FirstEnergy argue that the new contract demand transmission services \nare inconsistent with Commission precedent.275  Exelon and FirstEnergy contend that the \nCommission in the December Order contravened Order No. 888-A, in which the \nCommission rejected the notion of Network Customers “partially integrat[ing]” or \n“splitting a discrete load” because “such a split system creates the potential for a \ncustomer to game the system thereby evading some or all of its load-ratio cost \nresponsibility for network services.”276  We continue to find that the new contract \ndemand transmission services do not violate Order No. 888-A.277  Most simply, Order \nNo. 888-A rejected splitting load between NITS and PTPS at the same point of \ndelivery.278  That kind of splitting between transmission services at the same point of \ndelivery remains barred under the December Order:  Eligible Customers also cannot split \n \n272 Id.; see also id. PP 215-216 (explaining that an Eligible Customer taking NFCD \ntransmission service may reserve service as needed when the service is available, and the \nEligible Customer will be charged on an as-reserved contract demand basis). \n273 Id.; see also id. PP 215-216 (explaining that an Eligible Customer taking NFCD \ntransmission service may reserve service as needed when the service is available, and the \nEligible Customer will be charged on an as-reserved contract demand basis). \n274 Id. P 211. \n275 Exelon and FirstEnergy Request for Rehearing at 22-30. \n276 Id. at 23-24 (quoting Order No. 888-A, FERC Stats. & Regs. ¶ 31,048                    \nat 30,259) (internal quotation marks omitted). \n277 December Order, 193 FERC ¶ 61,217 at P 211. \n278 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,260."},{"page":64,"startToken":24027,"endToken":24492,"text":"Docket No. EL25-49-002, et al. \n- 64 - \nload between NITS and FCD or NFCD transmission service at the same point of delivery.  \nFurther, under the new contract demand services, load is neither split nor partially \nintegrated.  Instead, load is capped at contract demand and Eligible Customers taking \ntransmission service on behalf of Co-Located Loads are charged for that contract \ndemand, irrespective of usage.  Moreover, the rationale underlying Order No. 888-A—\ngaming—is also not present here.279  The new contract demand transmission services will \nhelp avoid a cost shift to other transmission customers because Eligible Customers will \nnot be able to reduce their load-ratio share to avoid paying transmission costs or capacity \ncosts because their amount of FCD transmission service is fixed.280   \n Exelon and FirstEnergy further argue that the Commission contravened Order              \nNo. 888-A “[b]ecause the Commission has recognized that the [contract demand \ntransmission service] customers use the transmission system for some services (such as \nload following and black start),” which would render those customers “partially \nintegrated.”281  We disagree.  Receiving ancillary services, such as regulation and black \nstart, does not “integrate” a transmission customer into the transmission network—and \nparticularly not in the manner that NITS does.  Specifically, Order No. 888-A clarified \nthat a “request for network service is a request for the integration of a customer’s \nresources and loads,”282 and a PTPS customer is not integrated, as recognized by Order \n \n279 Id.  \n280 December Order, 193 FERC ¶ 61,217 at P 211.  We also note that the \nCommission justified its findings in Order No. 888-A by discussing “several fundamental \noperational problems associated with allowing partial network service.”  Order               \nNo. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,260.  Those operational problems are not \nraised or present here because neither FCD nor NFCD transmission service are based on \nthe Eligible Customer’s load ratio.  Further, Exelon and FirstEnergy suggest that the \nDecember Order is inconsistent with Order No. 890.  Exelon and FirstEnergy Request for \nRehearing at 25-26 (citing Order No. 890, 118 FERC ¶ 61,119, order on reh’g, Order                          \nNo. 890-A, 121 FERC ¶ 61,297, order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 \n(2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228, order on clarification, \nOrder No. 890-D, 129 FERC ¶ 61,126).  While they do not cite a particular portion, they \nappear to be referring to a section that reiterates the already discussed portion of Order \nNo. 888-A.  Order No. 890, 118 FERC ¶ 61,119 at P 1619 (citing Order No. 888-A, \nFERC Stats. & Regs. ¶ 31,048 at 30,260-61).  Our findings as to Order No. 888-A thus \napply to Exelon and FirstEnergy’s citation to Order No. 890. \n281 Exelon and FirstEnergy Request for Rehearing at 24. \n282 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,260."},{"page":65,"startToken":24492,"endToken":24921,"text":"Docket No. EL25-49-002, et al. \n- 65 - \nNo. 888-A.283  Nonetheless, PTPS customers pay for and use ancillary services, including \nregulation service.  Therefore, whether an Eligible Customer taking transmission service \non behalf of Co-Located Load could receive ancillary services and/or black start service \nhas no bearing on whether it is “integrated” as a Network Customer.   \n Exelon and FirstEnergy also argue that the December Order is inconsistent with \nother Commission precedent.284  These cases do not undermine the December Order.  In \nseveral cited cases, Network Customers chose to take NITS and sought to receive the \nbenefits of NITS, specifically the right to withdraw energy from the transmission system \nwhen their own resources were not available, while arguing that they should be charged a \nlower rate based on their usage.285  For example, Amtrak relied on the transmission \nsystem when the nearby generator was not available, and sought to maintain that \narrangement and ability to withdraw energy to meet its gross load at any time, while \npaying NITS.286  Here, the new FCD and NFCD transmission services set up new \nobligations and benefits—as well as charges on that new basis.287  For example, under \n \n283 Id. at 30,259-60 (presenting binary of “fully integrated or not integrated”—with \nfull NITS or no NITS, respectively—in opposition to “partially integrated,” which would \ninclude NITS and PTPS). \n284 Exelon and FirstEnergy Request for Rehearing at 23-30 (citing Amtrak,                 \n171 FERC ¶ 61,237, order on reh’g, 173 FERC ¶ 61,043 (2020); Florida Power & Light, \n113 FERC ¶ 61,290, order on reh’g, 116 FERC ¶ 61,012, aff’d, 264 F. App’x 4; Idaho \nPower, 106 FERC ¶ 61,329; Ameren, 131 FERC ¶ 61,125; APS, 151 FERC ¶ 61,191). \n285 E.g., Amtrak, 173 FERC ¶ 61,043 at P 12 (“What Amtrak seeks to do is carve \nout from network service charges the power supplied by Safe Harbor.  Such an outcome \nis impermissible under the PJM Tariff and inconsistent with the nature of NITS.”). \n286 See id. P 13 (rejecting Amtrak’s rehearing request and explaining that “Amtrak \nseeks the ability to select when it will use and pay for NITS (i.e., only when inflows \noccur through PPL’s Manor Substation”)). \n287 December Order, 193 FERC ¶ 61,217 at PP 208, 210, 211, 212.  Indeed, the \nDecember Order also responds to new circumstances not present in the cited cases—\nnamely, the proliferation of potential Co-Location Arrangements.  Even if the cited cases \nwere controlling here, we find these new circumstances would warrant the Commission’s \ndecision to charge for FCD and NFCD transmission services based on the contract \ndemand."},{"page":66,"startToken":24921,"endToken":25362,"text":"Docket No. EL25-49-002, et al. \n- 66 - \nFCD transmission service, the Eligible Customer can rely on the service only up to the \nlevel of its contract demand.288 \n In particular, Exelon and FirstEnergy maintain that the December Order is \ninconsistent with Florida Power & Light, which they characterize as standing for the \nproposition that “the gross load construct [i]s most appropriate,” “even in the case of \nphysical impossibility of serving the entire load.”289  As an initial matter, there is no \n“physical impossibility exception”290 in the December Order because the new FCD and \nNFCD transmission services are based on legally capped demand, not “physical \nimpossibility.”291  Specifically, while in Florida Power & Light the “physical \nimpossibility” was a constraint on the transmission system, which prevented the entire \nload from being served by the transmission system,292 no such physical constraint on the \ntransmission system exists for an Eligible Customer taking FCD and/or NFCD \ntransmission service on behalf of a Co-Located Load.  Rather, such Eligible Customers \nmay elect to take transmission service at a contract demand level less than the amount of \nthe entire load and commit to limiting their withdrawals from the transmission system to \nthe contract demand level.  Regardless, in Florida Power & Light, the Commission only \ndiscussed “physical impossibility” in dicta.293  In that discussion, the Commission \n \n288 Id.  We further reiterate that the absence of this type of option is unjust and \nunreasonable.  Id. P 177.  \n289 E.g., Exelon and FirstEnergy Request for Rehearing at 24-25. \n290 Florida Power & Light, 113 FERC ¶ 61,290 at P 7.   \n291 December Order, 193 FERC ¶ 61,217 at PP 208, 210, 211, 212.  To the extent \nExelon and FirstEnergy characterize their argument addressed in this Part as directed \ntoward our “unjust and unreasonable” findings and not the replacement rate, Exelon and \nFirstEnergy Request for Rehearing at 22-23, we reject this argument based on the same \nsubstantive reasons included in this Part.   \n292 Florida Power & Light, 113 FERC ¶ 61,290 at PP 7-8.   \n293 Id.  The Commission began by generally rejecting the prospect of alternative \nproposals from individual customers because of the potential administrative and undue \ndiscrimination concerns with setting individual-customer-specific rates (but the \nCommission did approve the prospect of alternative proposals from utilities).  Id. P 6.  In \nother words, the cited adjudications, see, e.g., Exelon and FirstEnergy Request for \nRehearing at 23-25; see also id. at 27, are additionally inapposite here to the extent they \ninvolved proceedings where only individual customers that claimed to limit their use of \nthe transmission system sought to alter the rates, terms, and conditions of its transmission \nservice and obtain rates and terms for themselves."},{"page":67,"startToken":25362,"endToken":25721,"text":"Docket No. EL25-49-002, et al. \n- 67 - \nnonetheless did not even rule out the prospect of considering “physical impossibility” in a \nmore generally applicable setting where the impossibility could be administered, verified, \nand backed by technological and legal constructs—rather than on an ad hoc basis due to a \ntransmission customer’s mere assertions that it was particularly deserving of a              \nspecially-designed and administered service.294   \niv. \nAlleged Alternatives to FCD and NFCD \nTransmission Services \n(a) \nRequest for Rehearing \n Exelon and FirstEnergy contend that the Commission “fail[ed] to demonstrate that \n[the new transmission services] are just and reasonable” because there are already \nexisting mechanisms for customers to reduce load or use other generation in order to \nreduce withdrawals.295  Exelon and FirstEnergy maintain that PJM’s demand response \nrules are available to Co-Located Loads and the Commission fails to explain why such \nrules are inadequate here.  Indeed, Exelon and FirstEnergy assert, the Commission stated \nthat those rules are just and reasonable for Co-Located Loads taking NITS.  \n(b) \nDetermination \n We do not find Exelon and FirstEnergy’s argument availing.  The mere fact that \nthere may be preexisting mechanisms in the Tariff to accomplish something (even \nassuming that they are equivalent, which we do not) does not mean that adding an \nadditional mechanism is not just and reasonable.  Exelon and FirstEnergy offer no \njustification or citation to support the proposition that having multiple provisions targeted \nat similar objectives is not just and reasonable.  \n Further, demand response operates differently from the contract demand \ntransmission services.  In the first place, demand response is not a transmission service.  \nAnd demand response presents a different set of benefits and burdens—NFCD \ntransmission service would be curtailed earlier than demand response resources would be \ncalled on and can be instructed to curtail without any notification (unlike most demand \nresponse resources).296  FCD transmission service, on the other hand, is a firm \ntransmission service with the same curtailment priority as existing firm transmission \n \n294 Florida Power & Light, 113 FERC ¶ 61,290 at PP 7-8.  \n295 Exelon and FirstEnergy Request for Rehearing at 36-37. \n296 December Order, 193 FERC ¶ 61,217 at P 215; see also infra Part VI.G.4."},{"page":68,"startToken":25721,"endToken":26072,"text":"Docket No. EL25-49-002, et al. \n- 68 - \nservices, at the level of contract demand.297  In addition, PJM would not plan for any \nfuture load growth for either FCD or NFCD transmission service once the contract \ndemand level of each transmission service is established.  As to Interim NITS, that \ntransmission service serves a different function than demand response because it allows \nEligible Customers to begin taking a limited, non-firm transmission service on behalf of \nCo-Located Load before the transmission system is capable of reliably providing NITS at \ntheir requested level.  \nv. \nProtection Systems \n(a) \nRequest for Rehearing \n Exelon and FirstEnergy argue that the Commission’s emphasis on protection \nsystems is arbitrary and capricious because it is in tension with the Commission’s open \naccess policies.  Exelon and FirstEnergy assert that generators have an interest in \ndesigning captive arrangements where customers cannot access alternative supply, which \nis contrary to the Commission’s open access policies in Order No. 888.298  Exelon and \nFirstEnergy argue that generators will convert their interconnection facilities into \ntransmission assets and then install relay systems that make load captive to its \ngeneration.299  Exelon and FirstEnergy view this arrangement as akin to the problem of \ntransmission owners using their control of transmission facilities to refuse to deliver \nenergy produced by competitors or to deliver competitors’ power on less favorable \nterms.300 \n Exelon and FirstEnergy argue that the Commission erred in minimizing the fact \nthat protection systems can and have failed.301  Exelon and FirstEnergy point out that the \nCommission recognizes that protection systems fail, and to address this risk, directed \nPJM to apply a penalty rate for the new transmission services.  But Exelon and \nFirstEnergy allege that assessing penalties after the fact does not remediate the reliability \nimplications of faulty protection systems.  Exelon and FirstEnergy also argue that \nprotection systems “do not protect the grid from real impacts that occur even when there \n \n297 December Order, 193 FERC ¶ 61,217 at P 208. \n298 Exelon and FirstEnergy Request for Rehearing at 39-40. \n299 Id. at 40. \n300 Id. (citing N.Y. v. FERC, 535 U.S. at 8-9). \n301 Id. at 39-41."},{"page":69,"startToken":26072,"endToken":26352,"text":"Docket No. EL25-49-002, et al. \n- 69 - \nis consumption by a co-located customer but no net withdrawal, such as the impacts of \nload and voltage spikes and oscillations.”302 \n(b) \nDetermination \n We address both arguments in turn.  First, the contemplated use of necessary \ncontrol technologies and/or protection systems is not inconsistent with the Commission’s \nopen access policies.  Co-Location Arrangements are voluntary.  The December Order \ndoes not mandate that any Co-Located Load or Co-Located Generator enter into a                 \nCo-Location Arrangement.  In other words, contrary to Exelon and FirstEnergy’s \nassertions, the Commission is not forcing any entity into being a captive customer, as \nthey would have the option to connect to the transmission system and take NITS like any \nother Network Customer.  \n Second, we dismiss the argument regarding protection system failure and the risks \nthey address for lack of finality.303  The December Order did not make a final decision on \nrequired technology and what appropriate remedies would be for failure of that \ntechnology.304  Instead, the December Order set those issues for paper hearing \nprocedures.305  In any event, the Commission recognized that protection systems, like \nmany technologies, in rare instances can fail; accordingly, the Commission ordered paper \nbriefing on technical requirements to address reliability risks and remedial actions.306  We \nalso note that it is possible that the remedial actions could remediate the reliability \nimplications of such a failure.  Further, whatever risks are not avoided by a facility’s \nnecessary control technologies and/or protection systems will be studied in the relevant \nstudy processes.  \n \n302 Id. at 39. \n303 See supra P 106.  \n304 December Order, 193 FERC ¶ 61,217 at P 177.  \n305 Id. P 178.  \n306 Id. P 212."},{"page":70,"startToken":26352,"endToken":26675,"text":"Docket No. EL25-49-002, et al. \n- 70 - \nvi. \nBenefits of FCD and NFCD Transmission Services \n(a) \nRequest for Rehearing \n Exelon and FirstEnergy allege that the Commission is wrong to suggest that FCD \nand NFCD transmission services will promote efficiency or change siting.307  Exelon and \nFirstEnergy argue that planning and siting depend on physics and engineering of the grid, \nnot whether transmission service is charged on a gross or net load basis.  Exelon and \nFirstEnergy argue that the Commission’s decision to require FCD and NFCD \ntransmission services does not change how the study process should work.  Exelon and \nFirstEnergy warn that, “[i]f transmission providers are forced to pretend a 500 MW load \nis only 50 MW, or even that it is zero . . . it will threaten reliability and resource \nadequacy.”308  Exelon and FirstEnergy maintain that no loads should be taken out of the \nbroader planning process, and there is no support for the suggestion that regional \nplanning needs are reduced because of FCD and NFCD transmission services.  Exelon \nand FirstEnergy argue that the Commission’s decision on PJM’s retail BTMG netting \nrules and the Commission’s concerns about resource adequacy and cost shifting cannot \nbe reconciled with the Commission’s proposed structure for the new transmission \nservices.309 \n Exelon and FirstEnergy state that the Commission failed to point to any other \ntariff where these new transmission services have been required by the Commission.310 \n(b) \nDetermination \n As an initial matter, we dismiss this argument for lack of finality.311  The \nDecember Order did not make a final decision on the rates, terms, and conditions for the \nnew FCD and NFCD transmission services.312  Instead, the Commission found that \n“additional record evidence is needed” and set these issues for paper hearing \n \n307 Exelon and FirstEnergy Request for Rehearing at 47-48. \n308 Id. at 48. \n309 Id. at 48-49. \n310 Id. at 36. \n311 See supra P 106. \n312 December Order, 193 FERC ¶ 61,217 at P 219."},{"page":71,"startToken":26675,"endToken":27087,"text":"Docket No. EL25-49-002, et al. \n- 71 - \nprocedures.313  Without a final decision on the rates, terms, and conditions for the new \nFCD and NFCD transmission services, it is “premature” to argue or evaluate on rehearing \nwhether those as-yet-undeveloped services would affect efficiency or siting.314 \n In any event, while Exelon and FirstEnergy appear to direct this argument toward \nthe replacement rate, we addressed these topics in our discussion of the Commission’s \nFPA section 206 step one finding above.  In short, we continue to find that the Tariff is \nunjust and unreasonable because it does not include transmission services that reflect \nEligible Customers taking service on behalf of Co-Located Loads that are willing and \nable to limit their energy withdrawals from the transmission system under certain \nconditions—and that this lack of such transmission services is economically \ninefficient.315  We direct the new FCD and NFCD transmission services as a just and \nreasonable way to address this issue (among others).  And, while siting choices can \nreduce the need for Network Upgrades, that fact does not undermine our finding that \nrequiring Eligible Customers taking service on behalf of Co-Located Loads to take NITS \nfor these loads leads to an unacceptable probability of inefficient outcomes by requiring \nmore or more costly Network Upgrades than would potential new FCD and NFCD \ntransmission services.316  We similarly reiterate that the need for many Network \nUpgrades are caused by the amount of MW flow on the transmission system even though \nthe need for certain Network Upgrades are not (e.g., they may be caused by stability or \nvoltage-related issues).317  Therefore, as Exelon and FirstEnergy concede, under a \ntransmission service that reflects willingness and ability to limit energy withdrawals, “if \nthe load installs systems aimed at limiting its use of the grid, those might change the \nsystem impacts and need for upgrades.”318  Likewise, while PJM will only plan the \ntransmission system for FCD transmission service based on the level of contract demand \nas a matter of transmission capacity, PJM will still be able to consider the gross load for \nanalyzing certain issues such as stability and short circuit.319  \n \n313 Id. \n314 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. \n315 December Order, 193 FERC ¶ 61,217 at P 177. \n316 Id. PP 177, 199, 205. \n317 See Exelon and FirstEnergy Request for Rehearing at 47-48. \n318 Id. at 19-20; see also id. at 48. \n319 December Order, 193 FERC ¶ 61,217 at P 210."},{"page":72,"startToken":27087,"endToken":27472,"text":"Docket No. EL25-49-002, et al. \n- 72 - \n The Commission’s findings related to retail BTMG netting are not inconsistent \nwith the findings related to the new FCD and NFCD transmission services.320  The \nCommission stated that “the existing BTMG netting rules in the PJM Tariff [are] unjust \nand unreasonable” because, “under the existing Tariff, loads with BTMG are not fully \naccounted for in resource adequacy planning.”321  The Commission explained that \n“[s]uch loads must nevertheless be served, however, allowing them to lean on the PJM \nsystem when the [BTMG] is on a full or partial outage or if the load exceeds the rating of \nthe [BTMG].”322  Eligible Customers taking service on behalf of Co-Located Load will \nbe treated differently under FCD and NFCD transmission services—“PJM will have no \nobligation to serve the Eligible Customer beyond the contract demand.”323 \n Exelon and FirstEnergy argue that the Commission failed to point to any other \ntariff where these new transmission services have been required by the Commission.324  \nThis argument is irrelevant because the Commission need not point to another FPA \nsection 206 proceeding where the Commission set an identical replacement rate in order \nto set a replacement rate.   \nvii. \nReliability and New Transmission Services  \n(a) \nRequest for Rehearing \n Exelon and FirstEnergy argue that the Commission overlooked important \nreliability concerns in establishing new transmission services, including that loads impact \nthe system even when there is no net power draw on the system.325  Exelon and \nFirstEnergy assert that gross load is being followed by resources on the grid at all times, \nthus impacting the system.  Exelon and FirstEnergy assert that the Commission has not \nexplained how reliability planning should proceed when large loads may be incentivized \nto exceed their contract demand limit for transmission service.  Exelon and FirstEnergy \ncontend that the Commission overlooked resource adequacy risks in establishing Interim \nNITS.  Exelon and FirstEnergy allege that it is unclear how it will be determined that \nload may be served reliably and the Commission failed to give PJM guideposts to make \n \n320 See Exelon and FirstEnergy Request for Rehearing at 48-49.  \n321 December Order, 193 FERC ¶ 61,217 at P 179. \n322 Id. P 186. \n323 Id. P 211.  \n324 Exelon and FirstEnergy Request for Rehearing at 36; see also id at 27, 29, 35. \n325 Id. at 49-51."},{"page":73,"startToken":27472,"endToken":27845,"text":"Docket No. EL25-49-002, et al. \n- 73 - \nsuch a determination.  Exelon and FirstEnergy state that it is unknown how and by what \nstandards load would be curtailed and whether curtailment is an adequate response to the \nneed to follow gross load moment-by-moment, and thus the transmission service options \ncannot be just and reasonable.  \n Exelon and FirstEnergy argue that, as to Interim NITS, the Commission has not \naccounted for reliability risks, not knowing when or how curtailments would be \nimplemented, as the Commission has asked for briefing on when Eligible Customers \ntaking this service would be curtailed.326  Exelon and FirstEnergy express concern that \nfuture state legislation may create inconsistencies among Co-Located Load in different \nstates.  \n(b) \nDetermination \n We dismiss these arguments for lack of finality.327  The December Order did not \nmake a final decision on several issues relevant to this argument.328  Instead, the \nCommission found that “additional record evidence is needed” and established paper \nhearing procedures on:  the rates, terms, and conditions for the new transmission services; \ninterconnection requirements and operational practices for special protection schemes; \nthe communications, alarm, SCADA,329 or other requirements necessary for PJM to \nmonitor Co-Located Load transmission system demand status, ensure that relay settings \nare consistent with special protection scheme design, and inform system operator action \nin order to limit withdrawals that exceed the amount of contract demand; and the \nprocedures to govern circumstances under which PJM curtails an Eligible Customer \ntaking the three new transmission services.330  Without a final decision on these issues, it \nis premature to argue or evaluate on rehearing whether the Commission overlooked \nimportant reliability concerns in establishing the new transmission services.331  In any \nevent, as to the new FCD and NFCD transmission services, the December Order did not \n \n326 Id. at 37. \n327 See supra P 106. \n328 December Order, 193 FERC ¶ 61,217 at P 219. \n329 Supervisory Control and Data Acquisition (SCADA) is a system of remote \ncontrol and telemetry used to monitor and control the transmission system.  See NERC \nGlossary of Terms 42, https://www.nerc.com/globalassets/standards/reliability-\nstandards/glossary_of_terms.pdf. \n330 December Order, 193 FERC ¶ 61,217 at P 219. \n331 See Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8."},{"page":74,"startToken":27845,"endToken":28168,"text":"Docket No. EL25-49-002, et al. \n- 74 - \nprohibit PJM or the transmission owners from performing any particular studies that may \nbe necessary or mandate that the level of contract demand would be the only impact \nstudied.  For example, when PJM or the transmission owners consider factors unrelated \nto the contract demand of the Co-Located Load, the December Order did not preclude use \nof the complete dynamic or EMT model of the Co-Located Load, regardless of what level \nor type of transmission service the Eligible Customer has requested. \n On Interim NITS, specifically, the Commission established paper hearing \nprocedures on “What are the appropriate procedures to govern the circumstances under \nwhich PJM curtails an Eligible Customer taking the interim, non-firm transmission \nservice . . . on behalf of a Co-Located Load during emergency procedures?”332  The \nCommission thus did not make a final decision on this issue either.  In any event, the \nCommission stated that said Interim NITS “would only be available to the extent PJM \ndetermines that it can provide some level of interim service reliably.”333  \nviii. \nMajor Questions Doctrine \n(a) \nRequest for Rehearing \n Exelon and FirstEnergy assert that the Commission’s replacement rate violates the \nmajor questions doctrine.334  Exelon and FirstEnergy argue that the Commission has no \nauthority under FPA section 206 to provide unduly preferential treatment to a certain \ncategory of customers, but that the Commission established a replacement rate favoring \nCo-Located Load without reasoned explanation.   \n(b) \nDetermination \n We disagree with Exelon and FirstEnergy that the December Order violates the \nmajor questions doctrine.  The major questions doctrine applies in certain “extraordinary \ncases” involving an agency action that results in a “transformative expansion” of its \nauthority—especially over issues of great “economic and political significance.”335  In \n \n332 December Order, 193 FERC ¶ 61,217 at P 219. \n333 Id. P 200. \n334 Exelon and FirstEnergy Request for Rehearing at 52. \n335  W. Va. v. EPA, 597 U.S. 697, 721, 724 (2022) (citations and quotations \nomitted)."},{"page":75,"startToken":28168,"endToken":28634,"text":"Docket No. EL25-49-002, et al. \n- 75 - \nsuch “extraordinary cases,” courts might “hesitate before concluding that Congress meant \nto confer such authority.”336 \n We conclude that this proceeding is not an “extraordinary case” such that the \nDecember Order does not implicate the major questions doctrine.  In West Virginia v. \nEnvironmental Protection Agency, the U.S. Supreme Court identified a number of \nindicators that tend to identify a case as extraordinary, none of which are present here.  \nFirst, the December Order does not involve a “transformative expansion” of the FPA or a \nreimagining of the Commission’s long-held interpretation of that statute.337  Instead, the \nCommission acted, as it has previously, by finding that an existing practice was unjust \nand unreasonable and proceeding to establish a just and reasonable replacement rate.338  \nSecond, the December Order does not entail the use of an “ancillary” or “little-used \nbackwater” statutory provision.339  To the contrary, FPA section 206 is central to the \nCommission’s authority over the rates for transmission service in interstate commerce.340  \nThird, the Commission did not in the December Order act outside of the Commission’s \ntypical area of  “comparative expertise.”341  Indeed, the Commission’s regulation of the \n \n336 Id. at 721 (citations and quotations omitted). \n337 See id. at 724-25 (finding that an agency’s failure to invoke the asserted power \nin the past indicates that the major questions doctrine might apply). \n338 See, e.g., N.Y. v. FERC, 535 U.S. 1 (upholding Commission’s exercise of its \nFPA section 206 authority in its landmark Order No. 888, which established the               \npro forma OATT and established new transmission services); S.C. Pub. Serv. Auth. v. \nFERC, 762 F.3d 41 (upholding Commission’s exercise of its authority under FPA   \nsection 206 to remedy deficiencies in existing transmission planning practices). \n339 W. Va. v. EPA, 597 U.S. at 724, 730. \n340 See EPSA, 577 U.S. at 290 (“ensur[ing] effective transmission of electric \npower” is one of the “core objects” of the FPA”); N.Y. v. FERC, 535 U.S. at 7 (“[Section] \n205 of the FPA prohibited . . . unreasonable rates and undue discrimination with respect \nto any transmission . . . subject to the jurisdiction of the Commission, and [section] 206 \ngave the [Commission] the power to correct such unlawful practices.”) (quotations and \ncitations omitted); Bldg. for the Future Through Elec. Reg’l Transmission Plan. & Cost \nAllocation, Order No. 1920, 187 FERC ¶ 61,068 (2024), order on reh’g and clarification, \nOrder No. 1920-A, 189 FERC ¶ 61,126, at P 175 (2024) (“FPA section 206 sets forth \ncore Commission regulatory authority to remedy unjust and unreasonable rates, and \npractices affecting rates, for the transmission of electric energy in interstate commerce.”), \norder on reh’g and clarification, Order No. 1920-B, 191 FERC ¶ 61,026 (2025). \n341 W. Va. v. EPA, 597 U.S. at 729."},{"page":76,"startToken":28634,"endToken":28928,"text":"Docket No. EL25-49-002, et al. \n- 76 - \nrates, terms, and conditions of transmission service in interstate commerce sits at the core \nof the Commission’s expertise.342  Fourth, the December Order does not assert authority \nin a manner of great “economic and political significance.”343  Instead, the December \nOrder makes important but discrete changes to the manner in which a subset of \ntransmission customers take and pay for certain transmission services.   \n In any event, Exelon and FirstEnergy argue that the replacement rate violates the \nmajor questions doctrine only insofar as it exceeds the Commission’s jurisdiction or is \nunduly discriminatory or preferential.344  As explained above, the replacement rate does \nneither.   \nc. \nBTMG \ni. \nQualifying Facilities \n(a) \nDecember Order \n The Commission directed PJM to revise the Tariff to revise the retail BTMG \nnetting rules.345  The Commission directed PJM to propose a new MW threshold for the \namount of load at a particular electrical location that Network Customers may net by \nusing BTMG but to otherwise phase-in the elimination of netting.  Specifically, the \nCommission directed PJM to allow Network Customers already using the retail BTMG \nnetting rules to continue to do so for a transition period of three years.346  Further, the \nCommission directed PJM to grandfather entities with existing contracts for the specific \npurpose of effectuating a BTMG arrangement for the current term remaining under the \nexisting contract.347 \n \n342 See S.C. Pub. Serv. Auth. v. FERC, 762 F.3d at 49-54 (summarizing the \nCommission’s history of reforms to the rates, terms and conditions of interstate \ntransmission service). \n343 W. Va. v. EPA, 597 U.S. at 721. \n344 Exelon and FirstEnergy Request for Rehearing at 52. \n345 December Order, 193 FERC ¶ 61,217 at P 221. \n346 Id. P 223. \n347 Id. P 224."},{"page":77,"startToken":28928,"endToken":29292,"text":"Docket No. EL25-49-002, et al. \n- 77 - \n(b) \nRequest for Clarification and/or Rehearing \n Industrials request clarification on whether cogeneration QFs under the Public \nUtility Regulatory Policies Act of 1978 (PURPA) will be provided access to back-up and \nmaintenance power at just and reasonable rates and be credited for capacity based on the \nreliability of their generating units.348  Industrials contend that many QFs are \ncogeneration facilities, and that strong operational and financial incentives exist for \ncogeneration facilities to operate efficiently.  Industrials state that Commission \nregulations require certain QFs to meet specified efficiency standards and thus should be \nencouraged.349  Thus, Industrials argue that many QFs operate with a high capacity factor \nand reliably during transmission peaks.  Industrials accordingly seek clarification on \nwhether and how the December Order will apply to cogeneration QFs.  Industrials \ncontend that the removal of netting rules will “directly harm large American \nmanufacturing facilities that have invested substantial resources into developing and \nmaintaining on-site generation.”350  Industrials add that removing netting rules may \ncontradict Commission regulations that require back-up and maintenance services for \ncogeneration QFs.  Further, Industrials argue that FCD and NFCD transmission services \ndo not appear to account for forced generation outages.  For these reasons, Industrials \nrequest that the Commission clarify that cogeneration QFs are exempt from the “gross \nload” approach or that PJM must include a reasonable “Back-up Power” transmission \noption that retail BTMG customers, including QFs, can purchase.351 \n(c) \nDetermination \n As discussed below, in response to the Industrials’ request for clarification, we \nclarify and set aside, in part, the December Order.   \n First, we clarify that the December Order’s replacement rate does not change any \nobligation under the Commission’s PURPA regulations regarding QFs’ access to \nsupplementary, back-up, maintenance, and interruptible power.  The replacement rate \napplies only to Network Customers’ usage of NITS under the Tariff, and nothing in the \nreplacement rate undoes the requirement in 18 C.F.R. § 292.305(b)(1) that, as to QFs, \n“each electric utility shall provide . . . Supplementary power, Back-up power, \n \n348 Industrials Request for Clarification or Rehearing at 10; see also id. at 5. \n349 Id. at 11 (citing 18 C.F.R. § 292.205 (2025)).  \n350 Id. \n351 Id. at 11-13."},{"page":78,"startToken":29292,"endToken":29706,"text":"Docket No. EL25-49-002, et al. \n- 78 - \nMaintenance power, and Interruptible power.”352  While Industrials suggest that \nremoving netting rules may contradict Commission regulations that require back-up and \nmaintenance services for cogeneration QFs, Industrials do not explain how the \nreplacement rate results in Industrials no longer being entitled to back-up and \nmaintenance power under the Commission’s regulations.  In addition, Industrials do not \nexplain why it is necessary for the Commission to adopt a change to “credit [QFs] for \ncapacity based on the reliability of their generating units.”353 \n Second, we set aside, in part, the December Order’s directive that PJM establish a \nnew MW threshold for the amount of load at a particular electrical location that Network \nCustomers may net by using BTMG.354  We find that it is just and reasonable to allow \ncertain cogeneration QFs that are Network Customers to be able to net by using BTMG, \nand to be exempt from the new MW threshold, as discussed below.  In the December \nOrder, the Commission found that PJM’s retail BTMG rules are no longer consistent with \ncost causation principles because large loads configured in a BTMG arrangement with \nsignificant generation will raise cost-shifting concerns compared to loads pursuing \nsmaller amounts of netting.355  Moreover, the Commission found that PJM’s existing \nretail BTMG rules may lead to both reliability and resource adequacy risks because PJM, \nper its Tariff, is obligated to serve transmission customers using BTMG but does not \nconsider such customers in transmission and resource adequacy planning.356  We find that \nthere is not sufficient reason, and nor do Industrials articulate such a reason on rehearing, \nto believe that these concerns are inapplicable to cogeneration QFs categorically. \n However, we recognize, based on the record, that there may be certain industrial \ncogeneration QFs that may be integrated with load such that, when their generator trips \noffline, the load follows (rather than withdrawing energy from the transmission system).  \nFor example, as Industrials explain as to certain industrial cogeneration QFs, “if the \ngenerator goes offline, the load promptly follows because the manufacturing facility \n \n352 18 C.F.R. § 292.305(b)(1) (2025). \n353 Industrials Request for Clarification or Rehearing at 10.  \n354 December Order, 193 FERC ¶ 61,217 at P 221. \n355 Id. P 186. \n356 Id.  To the extent the Commission’s clarification on this issue conflicts with the \nrequested clarification, we otherwise disagree with Industrials’ request to the extent \nIndustrials request rehearing in the alternative.  See Industrials Request for Clarification \nor Rehearing at 2."},{"page":79,"startToken":29706,"endToken":30045,"text":"Docket No. EL25-49-002, et al. \n- 79 - \ncannot function without the steam output from the generation process.”357  We therefore \ndirect PJM, within 60 days of the date of issuance of this order, to submit on further \ncompliance a process to exempt certain cogeneration QFs from the new retail BTMG \nnetting rules if they demonstrate that they are integrated with load such that, when their \ngenerating facility trips offline, the load follows, and they thus do not present the \nreliability or resource adequacy concerns discussed in the December Order.  In \ndeveloping its compliance proposal, PJM must ensure that the requirements for a \ncogeneration QF to make this demonstration are not unduly burdensome. \nii. \nCapacity Obligations \n(a) \nDecember Order \n The Commission found that PJM’s existing retail BTMG netting rules may lead to \nboth reliability and resource adequacy risks because PJM is obligated to serve \ntransmission customers using BTMG but does not consider such customers in \ntransmission and resource adequacy planning.358  The Commission directed PJM to \npropose a new MW threshold for the amount of load at a particular electrical location that \nNetwork Customers may net by using BTMG.359  The Commission explained that such a \nthreshold should reduce the reliability and resource adequacy risks that large loads may \npose to PJM, while also allowing for Network Customers to reduce their transmission \ncharges in a transparent, not unduly discriminatory fashion. \n(b) \nRequest for Clarification and/or Rehearing  \n Industrials seek clarification that the removal of BTMG netting rules will only be \napplicable to transmission and specified ancillary services, not to capacity obligations.  \nIndustrials represent that the determination of retail customers’ capacity tags is made by \nindividual electric distribution companies and that large industrial and institutional users \nhave a variety of configurations and approaches to meeting their capacity \nrequirements.360  Industrials contend that the Commission did not analyze the impact of \n \n357 Industrials Request for Clarification or Rehearing at 11. \n358 December Order, 193 FERC ¶ 61,217 at P 186. \n359 Id. P 221. \n360 Industrials Request for Clarification or Rehearing at 15-16."},{"page":80,"startToken":30045,"endToken":30450,"text":"Docket No. EL25-49-002, et al. \n- 80 - \nthe BTMG rule changes on retail customers’ capacity obligations or address alternate \ncapacity products that a retail customer with BTMG could elect.361 \n(c) \nDetermination \n We deny Industrials’ clarification request and sustain the December Order.  The \nCommission’s determination that PJM’s retail BTMG netting rules are no longer just and \nreasonable rested on a finding that PJM’s existing retail BTMG netting rules may lead to \nreliability and resource adequacy risks.362  The Commission set a replacement rate to \nreduce the resource adequacy risks identified in the record.363  We recognize that \nrequiring PJM to revise its retail BTMG netting rules may affect capacity obligations,364  \nbut in the absence of this reform, the resource adequacy problems arising from PJM’s \nexisting retail BTMG netting rules would persist because PJM remains obligated to serve \ntransmission customers using BTMG but under the existing rules does not consider such \ncustomers in resource adequacy planning.365  As to Industrials’ concerns about the impact \nof the retail BTMG netting rule changes on retail customers, we agree with Industrials \nthat the RAA provisions Industrials cite directly apply to LSEs, not retail customers’ \ncapacity obligations,366 and we note that, as part of our replacement rate, we established a \ngrandfathering provision such that existing entities may be able to continue netting for \nthe remainder of a contract entered into for the purpose of effectuating a BTMG \narrangement.367  This grandfathering provision may also limit the impacts of the changes \nto PJM’s retail BTMG netting rules upon some entities’ capacity obligations.  In addition, \nas discussed above, we set aside, in part, the December Order and direct PJM to revise its \nTariff to extend the three new transmission services set forth in the December Order to \nEligible Customers taking service on behalf of load with BTMG that are willing and able \nto limit their energy withdrawals from the transmission system under certain conditions.  \nThus, Eligible Customers taking transmission service on behalf of load with BTMG that \n \n361 Id. at 16. \n362 December Order, 193 FERC ¶ 61,217 at P 186. \n363 Id. P 221. \n364 See, e.g., PJM, Intra-PJM Tariffs, RAA, Schedule 8 (Determination of \nUnforced Capacity Obligations) (5.3.0). \n365 December Order, 193 FERC ¶ 61,217 at P 186. \n366 See, e.g., PJM, Intra-PJM Tariffs, RAA, Schedule 8 (Determination of \nUnforced Capacity Obligations) (5.3.0). \n367 December Order, 193 FERC ¶ 61,217 at P 224."},{"page":81,"startToken":30450,"endToken":30780,"text":"Docket No. EL25-49-002, et al. \n- 81 - \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions may elect to take FCD and/or NFCD transmission service, which could \nreduce capacity obligations in comparison to a BTMG arrangement where the Eligible \nCustomer elects to take NITS.368 \niii. \nUnlawful Taking of Private Property \n(a) \nDecember Order \n In the December Order, the Commission directed PJM to revise the retail BTMG \nnetting rules in the Tariff.369 \n(b) \nRequest for Clarification and/or Rehearing \n Industrials argue that the Commission’s BTMG findings effectuate an unlawful \ntaking of private property without providing just compensation, in violation of the Fifth \nAmendment of the United States Constitution.  Industrials contend that there is a “per se \ntaking[]” because “the owner is deprived of ‘all economically beneficial us[e]’ of the \nproperty due to the government action.”370  Industrials assert that certain manufacturing \nfacilities with on-site generation would be “completely uneconomic.”371  Separately, \nIndustrials contend that there is a regulatory taking under the factors outlined in Penn \nCentral Transportation Co. v. New York City.372  In particular, Industrials state that the \nBTMG netting findings will cause, in some instances, devastating economic impacts “but \nperhaps not total deprivation.”373  Industrials also argue that the BTMG netting findings \n \n368 Id. P 211 (“PJM will only plan the transmission system and procure generation \ncapacity for the contract demand—not for load growth, like it does for NITS customers—\nand PJM will have no obligation to serve the Eligible Customer beyond the contract \ndemand.”); id. P 218 (“The new Non-Firm Contract Demand transmission service will \nnot include a charge for generation capacity.”). \n369 Id. P 221. \n370 Industrials Request for Clarification or Rehearing at 31-32 (quoting Lingle v. \nChevron U.S.A., 544 U.S. 528, 538 (2005)).  \n371 Id. at 32 (listing examples). \n372 Id. at 33 (citing Penn. Cent. Transp. v. City of N.Y., 438 U.S. 104, 124 (1978)). \n373 Id. at 33-34."},{"page":82,"startToken":30780,"endToken":31152,"text":"Docket No. EL25-49-002, et al. \n- 82 - \nupset investment-backed expectations and do not “promote or facilitate a public program \nor public good to justify the economic interference.”374  \n(c) \nDetermination \n As an initial matter, we dismiss Industrials’ argument that the Commission’s \nBTMG findings effectuate an unlawful taking of private property for lack of finality.375  \nThe December Order did not make a final decision on the applicability and design of the \nrevised retail BTMG netting rules.376  In particular, the Commission stated that it “ma[d]e \nno finding in this order on a threshold” “for the amount of load at a particular electrical \nlocation that Network Customers may net by using BTMG.”377  It would thus be \npremature to argue or evaluate on rehearing whether those as-yet-undeveloped retail \nBTMG netting rules effectuate an unlawful taking.378 \n In any event, the Commission has an obligation under the FPA to ensure that the \nrates, terms, and conditions of jurisdictional service are just and reasonable.  As the \nCommission found in the December Order, circumstances have changed since the \nCommission approved PJM’s retail BTMG netting rules such that these rules are no \nlonger just and reasonable.379  The Commission therefore is establishing a just and \nreasonable replacement rate.  And, as the Courts have held, in the context of setting rates, \nterms, and conditions for jurisdictional service, what is just and reasonable is not a \ntaking.380  Instead, in establishing a just and reasonable replacement rate, the Commission \nis balancing the respective rights and obligations of the parties and will determine that \n \n374 Id. \n375 See supra P 106. \n376 December Order, 193 FERC ¶ 61,217 at P 221. \n377 Id. \n378 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. \n379 December Order, 193 FERC ¶ 61,217 at P 186. \n380 See In re Permian Basin Area Rate Cases, 390 U.S. 747, 770 (1968) (“[T]he \njust and reasonable standard of the Natural Gas Act coincides with the applicable \nconstitutional standards and any rate selected by the Commission from the broad zone of \nreasonableness permitted by the Act cannot properly be attacked as confiscatory.”) \n(punctuation and citations omitted); see also N.Y. Indep. Sys. Operator, Inc., 151 FERC \n¶ 61,075, at P 63 (2015)."},{"page":83,"startToken":31152,"endToken":31426,"text":"Docket No. EL25-49-002, et al. \n- 83 - \nappropriate replacement rate through the course of the paper hearing and compliance \nproceedings.381   \niv. \nMateriality Threshold \n(a) \nDecember Order \n The Commission directed PJM to propose a new MW threshold for the amount of \nload at a particular electrical location that Network Customers may net by using \nBTMG.382  The Commission stated that parties would have an opportunity to comment \non PJM’s proposed threshold before we establish this replacement rate.383 \n(b) \nRequest for Clarification and/or Rehearing \n Industrials seek clarification that any retail BTMG materiality threshold \nimplemented will be sufficiently high to permit traditional manufacturers and institutional \ncustomers to continue to net generation, consistent with actual use of the transmission \nsystem.384  Industrials argue that a threshold of at least 200 MW would appropriately \nrecognize the major energy investments most existing industrial and institutional loads \nhave made over decades, consistent with the “actual use” principle, without making \n \n381 N.Y. Indep. Sys. Operator, Inc., 151 FERC ¶ 61,075 at P 63 (citing Jersey Cent. \nPower & Light Co. v. FERC, 810 F.2d 1168, 1191 (D.C. Cir. 1987) (en banc) (Starr, J. \nconcurring) ((“Unlike garden-variety takings, the requirements of the Takings Clause are \nsatisfied in the rate regulatory setting when justice is done, that is to say the striking of a \nreasonable balance between competing interests.”)); see also supra P 137 (describing the \nmateriality threshold, phase-in, and grandfathering), PP 141-142 (setting aside the \nDecember Order in part to allow certain cogeneration QFs to continue to net). \n382 December Order, 193 FERC ¶ 61,217 at P 221. \n383 Id. \n384 Industrials Request for Clarification or Rehearing at 16."},{"page":84,"startToken":31426,"endToken":31730,"text":"Docket No. EL25-49-002, et al. \n- 84 - \nuneconomic their resource adequacy contributions.385  Industrials contend that this \nthreshold would still address the primary concern driven by new large loads.386 \n To the extent the Commission does not grant clarification, Industrials argue that \nthe MW materiality threshold, transition period, and grandfathering provision fail to \ncorrect the asserted defects created in the December Order.387  While Industrials \n“welcome exemptions as helpful,” they describe those policies as “the exception that \nproves the rule.”388  Industrials contend that the threshold could create unintended \nconsequences such as perverse incentives to make on-site generation projects smaller, \nundue discrimination via a bright-line threshold, or a limit that is too low.389  Industrials \nsuggest that, rather than an arbitrary threshold, the Commission should maintain its \ntraditional netting approach but find alternative means to ensure that standby or backup \ncosts are addressed for very large loads.  Industrials recommend that if the Commission \npursues a mandatory threshold, it should choose a multi-pronged threshold aligned with \nthe drivers of current transmission demand and the reliability risks posed.390  Specifically, \nIndustrials argue, the Commission should set the threshold high enough to permit \ntraditional manufacturers and industrial loads to continue netting—such as 200 MW.391 \n \n385 Id. at 16 & n. 23 (“We understand that industrial combined heat and power . . . \nunits may, in certain cases, exceed 200 MW.  Given the Administration’s interest in \nreshoring American manufacturing and the pressing need to keep long-established \ngeneration units economic, 200 MW may be insufficient.”).   \n386 Id. at 16-17. \n387 Id. at 42.  \n388 Id. \n389 Id. at 42-43 (stating also that “[n]either a MW-based threshold nor a \ngrandfathering provision correct jurisdictional deficiencies” and the Commission should \n“find alternative means to ensure that standby or backup costs are addressed for very \nlarge loads”). \n390 Id. at 43.  \n391 Id. at 43-44."},{"page":85,"startToken":31730,"endToken":32154,"text":"Docket No. EL25-49-002, et al. \n- 85 - \n(c) \nDetermination \n As an initial matter, we dismiss Industrials’ argument that any retail BTMG \nmateriality threshold implemented will be insufficiently high for lack of finality.392  The \nDecember Order did not make a final decision on the materiality threshold to be used in \nthe revised the retail BTMG netting rules.393  In particular, the Commission stated that it \n“ma[d]e no finding in this order on a threshold” “for the amount of load at a particular \nelectrical location that Network Customers may net by using BTMG.”394  It would thus \nbe premature to argue or evaluate on rehearing whether that as-yet-undeveloped retail \nBTMG materiality threshold be insufficiently high.395 \n In response to the Industrials’ arguments on rehearing regarding the MW \nthreshold, transition period, and grandfathering provision, we continue to find that this \nthree-pronged approach as to a replacement rate is just and reasonable.396  As an initial \nmatter, we note that Industrials primarily take issue with the Commission’s decision to \nset a MW threshold, alleging it is arbitrary and may be unduly discriminatory.397  We \ndisagree.  We recognize that no threshold may be perfect, but the Commission has \ndiscretion in drawing administrative lines it deems necessary,398 and we continue to \nbelieve that a threshold is not only necessary for the reasons set out in the December \nOrder, but also that we can exercise reasonable discretion to set a threshold consistent \nwith the Commission’s intent to reduce the concerns raised by PJM’s existing retail \nBTMG netting rules.  As the Commission explained in the December Order, “such a \nthreshold should reduce the reliability and resource adequacy risks [] that large loads may \n \n392 See supra P 106. \n393 December Order, 193 FERC ¶ 61,217 at P 221. \n394 Id. \n395 Algonquin Gas Transmission, 175 FERC ¶ 61,150 at P 8. \n396 December Order, 193 FERC ¶ 61,217 at PP 221-224. \n397 Industrials Request for Clarification or Rehearing at 16-17, 42-43. \n398 See Vonage Holdings Corp. v. FCC, 489 F.3d 1232, 1242 (D.C. Cir. 2007) (“It \nis true that an agency may not pluck a number out of thin air when it promulgates rules in \nwhich percentage terms play a critical role.  When a line has to be drawn, however, the \nCommission is authorized to make a ‘rational legislative-type judgment.’  If the figure \nselected by the agency reflects its informed discretion, and is neither patently \nunreasonable nor ‘a dictate of unbridled whim,’ then the agency’s decision adequately \nsatisfies the standard of review.”) (citation and internal quotation marks omitted)."},{"page":86,"startToken":32154,"endToken":32532,"text":"Docket No. EL25-49-002, et al. \n- 86 - \npose to PJM, while also allowing Network Customers to reduce their transmission \ncharges in a transparent, not unduly discriminatory fashion.”399  The Commission also \nacknowledged that such a materiality threshold “will not eliminate the risk” identified in \nthe December Order, but found that it “will ensure that the risk is limited.”400  As the \nCommission explained in the December Order, an important part of the problem is that \n“PJM’s existing retail BTMG netting rules do not limit the amount of qualifying load that \na Network Customer may net by using BTMG.”401  We also note that, as discussed \nabove, we set aside, in part, the December Order’s elimination of BTMG netting as to \ncertain cogeneration QFs.  In addition, we note that above we set aside, in part, the \nDecember Order and extend the three new transmission services set forth in the \nDecember Order to Eligible Customers taking service on behalf of load with BTMG that \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions, thereby providing such customers the option to elect to take a \ntransmission service that matches their preferred use of the transmission system.402  \nLastly, we note that, while Industrials suggest the Commission find an alternative \napproach to a mandatory threshold to ensure that standby or backup costs are addressed \nfor “very large loads,”403 they fail to support their request with any specificity.404  \n \n399 December Order, 193 FERC ¶ 61,217 at P 221. \n400 Id. \n401 Id. P 186. \n402 Id. P 194 (stating that “Eligible Customers, on behalf of the Co-Located Loads \nthat they represent, may choose the transmission services that match their preferred use of \nthe transmission system”). \n403 Industrials Request for Clarification or Rehearing at 43. \n404 FPA section 313(a) requires that an “application for rehearing shall set forth \nspecifically” its grounds.  16 U.S.C. § 825l(a) (emphasis added).  We follow Commission \npractice, with which courts have agreed, and reject arguments on rehearing, such as this \none, lacking sufficient specificity.  PJM Interconnection, L.L.C., 171 FERC ¶ 61,040                 \nat P 22; see also Ind. Util. Regul. Comm’n, 668 F.3d at 736; LA Storage, LLC, 182 FERC \n¶ 61,026 at P 25 & n.75."},{"page":87,"startToken":32532,"endToken":32919,"text":"Docket No. EL25-49-002, et al. \n- 87 - \n2. \nNecessary Study Process for Existing Interconnection Customers \na. \nTreatment of Capacity Interconnection Rights (CIRs) for \nCo-Located Generators \ni. \nDecember Order \n The Commission found that an existing generator may not begin serving                    \nCo-Located Load that is not Network Load until it has de-listed its CIRs for the portion \nof the generator to be designated to serve any Co-Located Load that is not receiving \nNITS.405  A capacity resource’s CIRs are rights to inject generation as a Generation \nCapacity Resource into the transmission system at the Point of Interconnection.406   \nii. \nRequest for Clarification and/or Rehearing \n Constellation argues that the December Order appears to require a capacity \nresource to delist its CIRs even when the capacity resource remains fully capable of \nserving the grid during capacity emergencies.407  Constellation explains that generators \nand Co-Located Load may seek contractual arrangements in which the generator will \nserve the grid rather than the Co-Located Load during a capacity emergency and the             \nCo-Located Load will either curtail or rely on backup generation.  Constellation claims \nthat it would be inconsistent with PJM’s existing rules to require delisting in these \ncircumstances.  According to Constellation, PJM’s existing rules only require a capacity \nresource entering an external sale to delist its CIRs when the resource “has a financially \nand physically firm commitment to an external sale of its capacity.”408   \n Constellation therefore seeks clarification that the December Order does not \nrequire a capacity resource to delist its CIRs to serve a Co-Located Load that is taking \nNFCD transmission service if PJM can verify that the Co-Located Load has no \ncontractual right to energy from the generator during a capacity emergency and that the \nCo-Located Load has the ability either to curtail or draw on back-up power.409  \n \n405 December Order, 193 FERC ¶ 61,217 at P 230. \n406 PJM Interconnection, L.L.C., 168 FERC ¶ 61,155, at P 7 n.15 (2019). \n407 Constellation Request for Clarification or Rehearing at 3 (citing December \nOrder, 193 FERC ¶ 61,217 at P 230). \n408 Id. at 4 (quoting PJM, Intra-PJM Tariffs, OATT, attach. DD.6 § 6.6) (emphasis \nin original). \n409 Id. at 4-5 (referring to “the ability to (i) interrupt and/or (ii) turn on back-up \ndiesels or other back-up power or draw on batteries when transmission under the"},{"page":88,"startToken":32919,"endToken":33289,"text":"Docket No. EL25-49-002, et al. \n- 88 - \nConstellation argues that the Commission could require the Co-Located Load to disclose \ninformation regarding its protective relay scheme and its interruptible commitment and \ncould impose penalties on the Co-Located Load for failure to comply with its \ncommitment. \n To the extent that the Commission does not grant clarification, Constellation seeks \nrehearing.  Constellation argues that requiring a capacity resource to delist its CIRs in \nthese circumstances would be a failure of reasoned decision making.410  Constellation \nalso argues that it would be unduly discriminatory to require a capacity resource serving a \nCo-Located Load to delist for entering into an interruptible commitment but not to \nrequire capacity resources to delist before making other non-firm commitments.411 \niii. \nDetermination \n We deny Constellation’s request for clarification and sustain the December \nOrder’s finding that an existing generator may not begin serving Co-Located Load that is \nnot Network Load until it has delisted its CIRs for the portion of the generator to be \ndesignated to serve any Co-Located Load that is not receiving NITS.412 \n Constellation proposes a scenario in which an Eligible Customer taking NFCD \ntransmission service on behalf of Co-Located Load would not be allowed to withdraw \npower from the transmission system during emergency conditions and the Eligible \nCustomer would guarantee that it would further curtail its demand in order to allow the \nCo-Located Generator to provide energy to the system.  NFCD transmission service \ngoverns when an Eligible Customer may withdraw energy from the transmission system, \nbut it does not govern the firmness of any bilateral agreement to supply energy between \nthe Co-Located Load and the Co-Located Generator.  We understand Constellation’s \nscenario to be one in which the Co-Located Load—when relying on the Co-Located \nGenerator—does not schedule its power by relying on FCD or NFCD transmission \nservice.  \n \nnon-firm contract demand service is interrupted and the co-located generator is serving \nthe grid”). \n410 Id. at 6 (citing Elec. Consumers Res. Council v. FERC, 747 F.2d 1511, 1513-14 \n(D.C. Cir. 1984)). \n411 Id. (citing 5 U.S.C. § 706(2)(A); Consol. Edison of N.Y., Inc. v. FERC, 45 F.4th \n265 (D.C. Cir. 2022)). \n412 December Order, 193 FERC ¶ 61,217 at P 230."},{"page":89,"startToken":33289,"endToken":33665,"text":"Docket No. EL25-49-002, et al. \n- 89 - \n Under Constellation’s scenario, the Co-Located Generator would not be capable of \nmeeting its entire capacity requirement.  In addition to the requirement to perform during \nemergencies, Generation Capacity Resources are required to offer into the Day-Ahead \nMarket throughout the delivery year.413  Constellation’s proposal would allow a \nGeneration Capacity Resource to violate this requirement and provide an inferior \ncapacity product (compared to other Generation Capacity Resources) for the same \ncapacity payment.  We thus deny Constellation’s request for clarification and sustain the \nDecember Order. \n We also reject Constellation’s argument that Generation Capacity Resources \nengaged in non-firm external bilateral transactions are not required to delist their CIRs \nand are comparable.414  A Generation Capacity Resource engaged in a non-firm external \nbilateral transaction must still make offers into PJM’s day-ahead market.415   \nb. \nCost Responsibility for Network Upgrades \ni. \nDecember Order \n In the December Order, the Commission required PJM to revise its Tariff to \nexpressly indicate that the Interconnection Customer will be responsible for the costs of \nany modifications or Network Upgrades that are needed as a result of PJM’s study of the \nchange to the Interconnection Service Agreement (ISA) or Generation Interconnection \nAgreement (GIA) to allow the existing generator to serve Co-Located Load, including to \nreflect any reduction in CIRs, inclusive of all necessary Network Upgrades.  The \nCommission found that this change will clarify that costs associated with such                      \nCo-Location Arrangements will not be unfairly shifted to other transmission customers.  \nThe Commission further directed PJM to revise its Tariff to clarify that an existing \ngenerator may not commence service to a Co-Located Load until all required Network \nUpgrades, special protection schemes, and metering are in service.416 \n \n413 Under the Tariff, a capacity resource is required to offer its Installed Capacity \n(ICAP) equivalent of the resource’s cleared Unforced Capacity (UCAP) into the PJM \nenergy markets every day if not on outage or derated.  PJM, Intra-PJM Tariffs, OATT, \nattach. K, app. § 1.10 (Scheduling) (46.1.1), § 1.10.1A(d). \n414 Constellation Request for Clarification or Rehearing at 6. \n415 PJM, Intra-PJM Tariffs, OATT, attach. K, app. § 1.10 (46.1.1), § 1.10.1A(d). \n416 December Order, 193 FERC ¶ 61,217 at P 228; see also id. P 176 \n(summarizing same)."},{"page":90,"startToken":33665,"endToken":34031,"text":"Docket No. EL25-49-002, et al. \n- 90 - \nii. \nRequest for Rehearing \n Exelon and FirstEnergy challenge the Commission’s directive that an \nInterconnection Customer seeking to serve Co-Located Load using an existing generator \nmust bear the costs of all Network Upgrades.417  Exelon and FirstEnergy contend that the \nCommission has departed, without explanation, from its policy that all transmission \ncustomers share the embedded costs of the transmission system, including Network \nUpgrade costs, consistent with cost causation principles.418  Exelon and FirstEnergy \nassert that this policy is sensible because all loads benefit from the transmission network, \nincluding Co-Located Load.  Exelon and FirstEnergy argue that the Commission \nacknowledges that Co-Located Load benefits from the transmission network as a whole \nbecause the Commission found Co-Located Load relies on regulation and black start.419  \nExelon and FirstEnergy contend that regulation and black start cannot be delivered in \nisolation:  they depend on diverse resources around the grid transmitting power over \ntransmission lines, on other operating reserves and voltage support services, and on \nNetwork Upgrades.  Exelon and FirstEnergy also argue that the December Order is \ninternally inconsistent and discriminatory because it preserves NITS as a just and \nreasonable approach, but the NITS funding model conflicts with the proposed assignment \nof costs to Co-Located Load.420 \n Exelon and FirstEnergy assert that the Commission should not erode its rolled-in \nrate policy and identify several consequences of such erosion.421  First, Exelon and \nFirstEnergy contend that, if Co-Located Loads need only pay for incremental investment, \nthey avoid paying for the broader system on which they depend, resulting in other \ncustomers paying a forced subsidy.422  Exelon and FirstEnergy express concern that, once \na Co-Located Load fulfills its responsibility for funding certain upgrades, prohibitions on \n“and” pricing mean the Co-Located Load would not be responsible for further \ntransmission service payments even though the transmission system requires \nmaintenance.  Second, Exelon and FirstEnergy argue that the Commission’s approach \ncreates challenges akin to those in the generator interconnection space, such as the \npotential for future Co-Located Load customers to trigger significant upgrades, and \n \n417 Exelon and FirstEnergy Request for Rehearing at 42-43. \n418 Id. at 42. \n419 Id. at 43. \n420 Id. at 44. \n421 Id. at 44-47. \n422 Id. at 45."},{"page":91,"startToken":34031,"endToken":34441,"text":"Docket No. EL25-49-002, et al. \n- 91 - \nincentives for speculative behavior and Point of Interconnection shopping.423  Third, \nExelon and FirstEnergy argue that significant up-front requirements could hinder \neconomic development for Co-Located Load customers that are not data centers.  \niii. \nDetermination \n We sustain the December Order’s requirement that an Interconnection Customer \nwill be responsible for the costs of any modifications or Network Upgrades that are \nneeded to allow the existing generator to serve Co-Located Load, including to reflect any \nreduction in CIRs, inclusive of all necessary Network Upgrades.424  We disagree with \nExelon and FirstEnergy’s argument that the Commission created a “new paradigm” as to \nInterconnection Customers’ cost responsibility for Network Upgrades needed to \naccommodate modifications those customers make to their own generators.425  To the \ncontrary, the Commission directed PJM to revise the Tariff to expressly state that \nInterconnection Customers have this cost responsibility in order to “clarify that costs \nassociated with such Co-Location Arrangements will not be unfairly shifted.”426  In other \nwords, even without this revision to improve the Tariff’s clarity, this requirement was the \npreexisting one.  The Tariff provides that an Interconnection Customer is responsible for \nthe costs of additions to the Transmission System that are required to accommodate \nmodifications to the generator.427  For example, apart from Co-Location Arrangements, if \nan Interconnection Customer decreased the capacity of a generator due to technological \nchanges at that facility, the Interconnection Customer would be responsible for the costs \nof Network Upgrades needed to accommodate that decrease.428  This requirement \n \n423 Id. at 46. \n424 December Order, 193 FERC ¶ 61,217 at P 228. \n425 Exelon and FirstEnergy Request for Rehearing at 42-47. \n426 December Order, 193 FERC ¶ 61,217 at P 228 (emphasis added).   \n427 PJM, Intra-PJM Tariffs, pt. IX, subpt. B, app. 2 (2.0.0), § 3.4(b) (Modification \nCosts) (“Project Developer shall be responsible for the costs of any additions, \nmodifications, or replacements to the Interconnection Facilities and Transmission Owner \nUpgrades or the Transmission System that are required, in accord with Good Utility \nPractice and/or to maintain compliance with Applicable Laws and Regulations or \nApplicable Standards, in order to accommodate additions, modifications, or replacements \nmade by Project Developer to the Generating Facility or Merchant Transmission Facility \nor to the Project Developer Interconnection Facilities.”); see also, e.g., id. Attachment O, \nAppendix 2, § 3.4(b) Modification Costs (0.0.0).  \n428 Id. Part IX.B, Appendix 2, § 3.4(b) Modification Costs (2.0.0)."},{"page":92,"startToken":34441,"endToken":34869,"text":"Docket No. EL25-49-002, et al. \n- 92 - \nlikewise applies to Interconnection Customers seeking to modify their interconnection to \nserve Co-Located Load if the attendant decrease in energy injected to the transmission \nsystem necessitates Network Upgrades.  Accordingly, if the Commission had not directed \nthe revision at issue here, Interconnection Customers would still bear the cost \nresponsibility at issue—the Commission simply acted to improve the clarity of the Tariff \non this topic.  Exelon and FirstEnergy thus attack a requirement in the Tariff that the \nCommission approved before this proceeding and that the Commission did not change in \nthis proceeding.   \n For the same reason, Exelon and FirstEnergy are incorrect in arguing that the \nCommission “depart[ed] from prior precedent” with a requirement that “differs from the \napproach taken in the PJM Tariff.”429  As explained, the Commission did not change the \npreexisting Tariff regime.  In any event, despite their assertion, Exelon and FirstEnergy \ndo not include citations to precedent addressing this topic.430   \n Exelon and FirstEnergy also misunderstand the requirement they criticize.  Exelon \nand FirstEnergy characterize the Commission’s directive as ordering that “[C]o-[L]ocated \n[L]oad must self-fund any needed transmission upgrades.”431  The cost responsibility at \nissue, however, is limited to existing Interconnection Customers and pertains only to the \nspecified Network Upgrades related to their own modifications.432  In short, the \nCommission did not direct that Co-Located Load would self-fund Network Upgrades.  \nTheir criticisms of the clarification that the Commission directed to the current Tariff are \nthus flawed.  The Commission specifically stated that the requirement to self-fund any \nneeded Network Upgrades was appropriate because when “an Interconnection Customer \nseek[s] to serve Co-Located Load using an existing generating facility” “existing \ntransmission customers” must be “protect[ed]” “from bearing the cost of Network \nUpgrades required for an Interconnection Customer to begin serving Co-Located \nLoad.”433  Otherwise, costs could be “unfairly shifted” based on the conduct of \n \n429 Exelon and FirstEnergy Request for Rehearing at 42, 44. \n430 In the relevant section of Exelon and FirstEnergy’s rehearing request, they do \ncite several cases and orders that do not address this topic.  For example, Exelon and \nFirstEnergy cite Coalition of MISO Transmission Customers v. FERC, 45 F.4th 1004, \n1009 (D.C. Cir. 2022), for a general statement of cost causation principles and they cite \ntwo orders regarding load-ratio share for NITS.  Id. at 42-47 & nn.110-111. \n431 Id. at 42. \n432 PJM, Intra-PJM Tariffs, pt. IX, subpt. B, app. 2, (2.0.0), § 3.4(b) (Modification \nCosts). \n433 December Order, 193 FERC ¶ 61,217 at P 176 (emphasis added)."},{"page":93,"startToken":34869,"endToken":35281,"text":"Docket No. EL25-49-002, et al. \n- 93 - \nInterconnection Customers.434  The entity responsible for causing the need for the \nNetwork Upgrade costs is therefore the relevant Interconnection Customer, and Exelon \nand FirstEnergy are incorrect to assert that a “load pays” framework should apply here.435  \nIt is the conduct of the Interconnection Customer that triggers the Network Upgrades at \nissue.  \n Exelon and FirstEnergy nonetheless contend that “[C]o-[L]ocated [L]oad should \nbe charged for the benefits it receives from the grid and for the burdens it places upon the \ngrid.”436  Exelon and FirstEnergy further give the example of the use of regulation and \nblack start services.437  The December Order appropriately addressed such use.  The \nDecember Order determined, for example, that Eligible Customers serving Co-Located \nLoads that seek to rely on the transmission system to the same extent as Network \nCustomers will continue to be eligible to take NITS, billed on a gross demand basis; \nEligible Customers can take and pay for the new contract demand transmission services \nthat reflect a Co-Located Load’s ability to limit withdrawals from the transmission \nsystem; and Eligible Customers taking transmission service on behalf of Co-Located \nLoad must be assessed charges for regulation and black start services on a gross demand \nbasis, to ensure appropriate cost recovery for such services.438  In sum, the findings we \ndiscuss here related to Interconnection Customer cost responsibility do not disturb the \nCommission’s findings addressing appropriate charges for transmission service—an \nobligation on Eligible Customers not Interconnection Customers.  \n Exelon and FirstEnergy also argue that the Commission improperly assessed “cost \ncausation” because it “randomly applied” “cost responsibility” “only to cases where the \nadded load is served through an existing generator interconnection facility.”439  As \nexplained above, however, the Commission simply applied the existing Tariff.  The \n \n434 Id. P 228. \n435 Exelon and FirstEnergy Request for Rehearing at 43; see also id. at 43-44 \nn.113 (stating that the December Order “departs from th[e] longstanding approach” of \n“rolling the costs of load-driven network upgrades into transmission rates”).  \n436 Id. at 43; see also id. at 45-46; id. at 47 (stating that “it should not be assumed \nthat large loads will trigger system upgrades with costs in excess of what they would \notherwise contribute to the system if they paid traditional network rates based on their \nload-share ratio”).  \n437 Id. at 43. \n438 December Order, 193 FERC ¶ 61,217 at P 160. \n439 Exelon and FirstEnergy Request for Rehearing at 44."},{"page":94,"startToken":35281,"endToken":35691,"text":"Docket No. EL25-49-002, et al. \n- 94 - \nCommission likewise affirmed the allocation of cost responsibility to the parties that \ncause the costs—the Interconnection Customers—who do so through their conduct in \nmodifying their existing arrangement.440  Accordingly, we disagree with Exelon and \nFirstEnergy’s assertion that these costs should instead be spread “to all network \ncustomers.”  In PJM, the costs of Network Upgrades are directly assigned to the \ninterconnection customer—referred to as participant funding.441  In its Order No. 2003 \ncompliance proceeding, PJM explained that “the ‘but for’ provisions of the PJM tariff . . . \nrequire an Interconnection Customer to pay 100 percent of the Network Upgrades that \nmust be made for the Interconnection Customer to connect to the PJM grid.”442  In PJM, \nInterconnection Customers are also responsible for the costs of any changes to the \ntransmission system that are required to accommodate additions, modifications, or \nreplacements made by the Interconnection Customer to the generator or its \ninterconnection facilities.443  The Commission’s directive thus adheres to Commission \nprecedent and the Tariff and also does not conflict with (or change) “the Network Service \nfunding model.”444 \n We also find unavailing the “several issues” Exelon and FirstEnergy contend the \nCommission’s determination created.445  We find each speculative and unsupported by \nevidence.  More specifically, Exelon and FirstEnergy assert that the Commission is \nimproperly accounting for a “benefit to other customers to include new [C]o-[L]ocated \n[L]oads in the pool of payers for the existing transmission network.”446  Yet as explained \nabove, the December Order establishes a set of transmission service options that ensures \nthat Eligible Customers taking service on behalf of Co-Located Loads are allowed to \n \n440 Indeed, Exelon and FirstEnergy acknowledge that “exiting incumbent \ngenerators” cause the relevant costs by referring to “transmission upgrade costs they \ncause by serving [C]o-[L]ocated [L]oad.”  Id. \n441 PJM Interconnection, L.L.C., 108 FERC ¶ 61,025, at P 20 (2004). \n442 Id. P 19.  PJM’s current generator interconnection rules include similar “but \nfor” provisions.  See PJM, Intra-PJM Tariffs, pt. VIII, subpt. C, § 404 (1.0.0), \n§ 404(A)(5) (Cost Allocation for Network Upgrades).  \n443 PJM, Intra-PJM Tariffs, pt. IX, subpt. B, app. 2, § 3.4 (2.0.0), § 3.4(b) \n(Modification Costs). \n444 Exelon and FirstEnergy Request for Rehearing at 44. \n445 Id. at 45-47 (including argument that the Commission’s “approach creates \nchallenging dynamics like those we have seen in the generator interconnection space”). \n446 Id. at 45-46."},{"page":95,"startToken":35691,"endToken":35996,"text":"Docket No. EL25-49-002, et al. \n- 95 - \nchoose the transmission service that aligns with their use of the transmission system and \ntherefore aligns the charges for service with the benefits received.  Exelon and \nFirstEnergy’s conjecture that “significant up-front requirements could hinder economic \ndevelopment”447 disregards the voluntary nature of Co-Location Arrangements, which \nreflect an additional opportunity for developers to consider. \n3. \nNew Generators Serving Co-Located Load \na. \nDecember Order \n In the December Order, the Commission found that the Tariff is unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity or \nconsistency the rates, terms, and conditions of service that apply to Interconnection \nCustomers serving Co-Located Load and Eligible Customers taking transmission service \non behalf of Co-Located Load.448  Pertinent to new generators, the Commission directed \nPJM to revise its Tariff to clarify that PJM shall consider requests for interconnection \nservice below the full generating capability of the generator, so that an Interconnection \nCustomer may request interconnection service at a level below its maximum facility \noutput to serve Co-Located Load;449 that Interconnection Customers seeking to use new \ngenerators to serve Co-Located Load may use existing procedures to accelerate a new \nservice request if the request has no cost allocation for Network Upgrades and does not \nrequire further studies;450 that an Interconnection Customer seeking to use a new \ngenerator to serve Co-Located Load may request provisional interconnection service;451 \nand that an Interconnection Customer seeking to use a new generator to serve Co-Located \nLoad at an existing Point of Interconnection may request Surplus Interconnection \nService, if the existing Interconnection Customer at that Point of Interconnection has \nmade Surplus Interconnection Service available.452 \n \n447 Id. at 46-47. \n448 December Order, 193 FERC ¶ 61,217 at P 159. \n449 Id. P 232. \n450 Id. P 233. \n451 Id. P 234. \n452 Id. P 235."},{"page":96,"startToken":35996,"endToken":36411,"text":"Docket No. EL25-49-002, et al. \n- 96 - \nb. \nRequest for Clarification \n Joint Parties request the Commission clarify that a Co-Located Load may \nnominate a net withdrawal limit in the same manner that it may nominate a net injection \nlimit when requesting new or modifying existing interconnection service.453  Joint Parties \nargue that the Commission found that creating new transmission services is necessary to \nensure that Co-Located Loads pay only for the services they use and to avoid costly and \ninefficient transmission system buildout, and that the same logic “should compel \ncomplementary reforms to the generator interconnection process, because that process \nalso may evaluate withdrawals from the Co-Located Load and therefore may also \nresult—absent clarification—in ‘costly and inefficient transmission system buildout.’”454  \nJoint Parties argue that clarification is necessary to realize the Commission’s intent of \nensuring that Co-Located Loads do not pay for services that they do not use and do not \ntrigger Network Upgrades that they do not need.  Joint Parties explain that, to the extent \nPJM performs interconnection service study steps involving withdrawal assumptions \nfrom both the storage facility and the Co-Located Load, those steps “must allow the \ninterconnection customer to provide for limits to the injection and withdrawal rights for \nthe generation and co-located load facilities reflecting the proposed integration of those \nfacilities.”455  Joint Parties clarify that they recommend against the Commission requiring \nCo-Located Load be included in the interconnection study process, as the timing of the \nload interconnection process may not match.456 \n Joint Parties argue that, without clarification, PJM may assume that the                         \nCo-Located Load and the charging load of the storage resource create overlapping grid \nimpacts, when both could be managed to limit the overall withdrawal of the resource and \navoid withdrawing energy when doing so would create grid impacts that necessitate \nNetwork Upgrades.  Joint Parties explain that, while the December Order recognizes that \n“co-located resources” can limit withdrawals and prevent unnecessary transmission \nbuildout, Joint Parties argue the order applies this logic only to transmission service and \nnot interconnection service.457  Joint Parties contend that not applying this logic to \ninterconnection service would reduce the benefits of creating the non-firm transmission \n \n453 Joint Parties Request for Clarification at 2-3, 5 (citing December Order,                   \n193 FERC ¶ 61,217 at P 232). \n454 Id. at 3 (citing December Order, 193 FERC ¶ 61,217 at P 177). \n455 Id. at 5-6. \n456 Id. at 8 n.20. \n457 Id. at 10 (citing December Order, 193 FERC ¶ 61,217 at P 199)."},{"page":97,"startToken":36411,"endToken":36718,"text":"Docket No. EL25-49-002, et al. \n- 97 - \nservice.458  Joint Parties request that the Commission require PJM to specify what \ninformation about the Co-Located Load is required for the purposes of the new service \nrequest study process, similar to the Commission’s requirement about the Necessary \nStudy process, to ensure that PJM does not include overlapping load and energy storage \nwithdrawals.459 \nc. \nDetermination \n We deny Joint Parties’ request for clarification.  Joint Parties’ request \nmisconstrues the findings in the December Order that the Tariff is unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity or \nconsistency the rates, terms, and conditions of service that apply to Interconnection \nCustomers serving Co-Located Load.460  The December Order did not require PJM to \nintegrate into the interconnection study process operating assumptions of both a                     \nCo-Located Load and electric storage resources that are part of a Co-Location \nArrangement.  PJM has already committed to studying the electric storage resources of \nInterconnection Customers as charging during off-peak periods, consistent with PJM’s \nfuel-based dispatch assumptions set forth in its planning criteria.461   \nD. \nInformational Report \n1. \nDecember Order \n In the December Order, the Commission directed PJM to submit in Docket             \nNo. EL25-49-000, within 30 days of the date of issuance of the December Order, a \ndetailed informational report addressing, among other things “the development of \nenhanced load forecasting . . . measures to assist PJM in determining the amount of new \ncapacity that is needed to maintain system reliability.”462 \n \n458 Id. at 9-10. \n459 Id. at 8 (citing December Order, 193 FERC ¶ 61,217 at P 227). \n460 December Order, 193 FERC ¶ 61,217 at P 159. \n461 PJM Interconnection, 195 FERC ¶ 61,031, at P 180 (2026) (accepting PJM’s \nproposal, in relevant part, in compliance with the Commission’s Order No. 2023 \ninterconnection reforms). \n462 December Order, 193 FERC ¶ 61,217 at PP 237-239."},{"page":98,"startToken":36718,"endToken":37107,"text":"Docket No. EL25-49-002, et al. \n- 98 - \n2. \nRequest for Clarification \n PIOs request clarification as to how the Commission intends to respond to or \notherwise use information provided in the record regarding PJM’s load forecasting \npractices.  PIOs further request that any subsequent order from the Commission address \nthe issues raised in the record regarding the continuing and ongoing deficiencies in PJM’s \nload forecasting process.  PIOs explain that PJM is using these load forecasts as inputs in \nthe upcoming Base Residual Auction and RTEP and argue that, without a specific \nCommission directive, PJM is unlikely to timely resolve issues that PIOs allege exist with \nthe load forecasts.463  PIOs note that the Commission required PJM to provide an \ninformational filing that includes an update regarding the development of “enhanced load \nforecasting” and acknowledge that the Commission stated that it “will not act on or notice \nthis informational [f]iling.”464 \n PIOs note that Commissioner Rosner submitted a letter to PJM about load \nforecasting in September 2025 and take issue with PJM’s October 2025 response.465  \nAccording to PIOs, PJM’s response to this letter does not require or specify a particular \nmethodology for forecasting large loads, without which PIOs allege that LSEs and \nElectric Distribution Companies will continue to report data with widely varying \naccuracy and that load forecasts will remain uncertain.  PIOs also argue that PJM’s \nresponse fails to identify a way for PJM to address the double counting of data centers or \nto enable PJM to respond dynamically to significant updates to load forecasts.466 \n PIOs contend that recent events have validated their concerns regarding the \naccuracy of PJM’s load forecasts.  For example, according to PIOs, PJM staff have \nacknowledged that the 2026 forecast would likely reflect a decrease in forecasted load for \nthat time period in light of an update to how PJM implements load adjustments.  Given \nthe alleged inaccuracy of PJM’s load forecasts, and because PJM uses its load forecasts \nto essentially set the demand curve for capacity obligations, for reliability studies, and to \nsupport the RTEP, PIOs question how these processes remain just and reasonable without \nsignificant revisions to PJM’s load forecasting practices.467 \n \n463 PIOs Request for Clarification at 2-3. \n464 Id. at 2 (citing December Order, 193 FERC ¶ 61,217 at P 238 & n.486). \n465 Id. at 4-5. \n466 Id. \n467 Id. at 5-7."},{"page":99,"startToken":37107,"endToken":37486,"text":"Docket No. EL25-49-002, et al. \n- 99 - \n3. \nDetermination \n We deny the request for clarification.  The directive in the December Order to \nPJM to file an informational report that includes load forecasting represents the \nCommission’s actions in this proceeding related to load forecasting.468  The Commission \nwill review the informational report in its normal course and remains committed to \nmonitoring PJM’s load forecasting.  Separately, we note that in the order that we are \nissuing concurrently in Docket No. EL26-67-000, we direct PJM to show cause as to why \nits Tariff remains just and reasonable without sufficiently clear and consistent Tariff \nprovisions that address the application process for requesting transmission service to \nEligible Customers on behalf of large loads and the study procedures for studying the \nprovision of transmission service to Eligible Customers on behalf of large loads, \nincluding a non-refundable application fee and sufficient readiness requirements that \nescalate at distinct phases of the study process to deter duplicative or speculative requests \nfor transmission service (e.g., meaningful milestones and/or financial commitments).   \nV. \nCompliance \nA. \nBTMG Rules \n1. \nMateriality Threshold \na. \nDecember Order \n The Commission found that PJM’s existing retail BTMG netting rules were no \nlonger just and reasonable and directed several changes, including directing PJM to \npropose a new MW threshold for the amount of load at a particular electrical location that \nNetwork Customers may net by using BTMG.469  The Commission found that a \nmateriality threshold would reduce the reliability and resource adequacy risks that large \nloads may pose to PJM, while also allowing for Network Customers to reduce their \ntransmission charges in a transparent, not unduly discriminatory fashion.  The \nCommission noted “as points of reference that PJM requires any generator larger than             \n10 MW to be individually metered and that the Commission’s definition of a small \ngenerator is 20 MW.”470 \n \n468 December Order, 193 FERC ¶ 61,217 at PP 237-239. \n469 Id. P 221.  The Commission did not direct PJM to make any changes to its rules \nfor Non-Retail BTMG, finding that the record did not demonstrate the need for changes \ngiven that Non-Retail BTMG is already capped.  Id. P 222.  \n470 Id. P 221 (citing PJM Manual 14G:  Generation Interconnection Requests,            \nRev. 8 (eff. July 26, 2023), § 1.6.2; Standardization of Small Generator Interconnection"},{"page":100,"startToken":37486,"endToken":37851,"text":"Docket No. EL25-49-002, et al. \n- 100 - \nb. \nPJM Compliance Filing \n PJM proposes to modify the existing Tariff definition of BTMG and add a new \ndefinition for Retail BTMG to establish a materiality threshold for Retail BTMG.471  PJM \nexplains that the current Tariff definition of BTMG includes both Retail and Non-Retail \nBTMG, but the Tariff only specifically defines Non-Retail BTMG.472  Therefore, PJM \nproposes to separately define Retail BTMG as BTMG that is used to serve a retail load \nserved by a Network Customer located at the same electrical location, where such \ngeneration has a cumulative nameplate rating of no greater than 50 MW.473  PJM also \nproposes to clarify in the Tariff that Retail BTMG may not be part of a Co-Located Load \nconfiguration.  PJM argues that this clarification is necessary “to avoid unexpected and \nunintended hybrid scenarios mixing BTMG and the new transmission service \nproducts.”474 \n PJM states that the proposed materiality threshold, along with other exclusions \ndiscussed below, will avoid the “unintended consequence of causing Retail BTMG \nresources to prematurely cease operations and discontinue investment in grid-enhancing \nbackup generation,” which may otherwise impact system reliability.475  PJM argues that a \nlower threshold of 10 or 20 MW would likely exclude Retail BTMG with limited impact \non the transmission system in comparison to Co-Located Load coming online today.  \n \nAgreements & Procs., Order No. 2006, 111 FERC ¶ 61,220, at P 1, order on reh’g, Order \nNo. 2006-A, 113 FERC ¶ 61,195 (2005), order granting clarification, Order No. 2006-B, \n116 FERC ¶ 61,046 (2006)). \n471 Compliance Transmittal at 6-7 (citing December Order, 193 FERC ¶ 61,217              \nat P 179). \n472 Id. at 5-6 (citing PJM, Intra-PJM Tariffs, pt. I, Definitions A-B (24.0.0), Behind \nThe Meter Generation; PJM, Proposed Tariff, PJM, pt. I, Definitions L-M-N (52.0.0), \nNon-Retail Behind The Meter Generation).  PJM explains Non-Retail BTMG is BTMG \nused to net load through a distribution system.  PJM clarifies that no substantive changes \nare proposed to the Non-Retail BTMG netting rules, but PJM does propose clarifying \nTariff edits to avoid confusion with the new retail BTMG netting rules.  Id. at 7, 15-16. \n473 Id. at 7. \n474 Id. at 18. \n475 Id. at 12."},{"page":101,"startToken":37851,"endToken":38237,"text":"Docket No. EL25-49-002, et al. \n- 101 - \nPJM also contends that many of the lower MW generators would not be willing to enter \nthe interconnection queue due to age and the potential cost of Network Upgrades.476 \n PJM also proposes to exclude on-site backup generation at the same electrical \nlocation as the retail load that can only be used to serve such retail load during conditions \nthat may threaten the integrity or reliability of the PJM region or the regional power \nsystem from the 50 MW materiality threshold, arguing that to do otherwise would \ndisincentivize retail customers from installing backup generation that would improve \nreliability.477  PJM notes that the Department of Energy recently issued an order during \nWinter Storm Fern directing PJM to direct backup generation resources to operate before \ntaking certain emergency actions.478  PJM states that exempting backup generation from \nthe materiality threshold will ensure this reliability tool remains available.  Finally, PJM \nstates that a materiality threshold based on the size of the generator that may qualify as \nRetail BTMG, rather than the amount of load that may net, establishes a clear and bright \nline for what can continue qualifying as Retail BTMG, given that the size of a load may \nfluctuate.479 \n PJM states that, should the Commission not accept PJM’s proposal regarding \ngrandfathering, discussed below, PJM requests the Commission to allow a higher interim \ninitial materiality threshold for the start of the transition period to avoid causing Retail \nBTMG to cease operations and exacerbate the resource adequacy issues in PJM.480  PJM \nstates that, should the Commission take this path, PJM would commit to reviewing \nadditional data on the size and extent of existing Retail BTMG to inform a final \nthreshold. \nc. \nPleadings \ni. \nSize of Threshold \n Constellation argues that PJM’s proposed 50 MW materiality threshold for BTMG \nis too high and urges the Commission to either reject it or require modifications to \n \n476 Id. at 12-13. \n477 Id. at 13 (citing US Department of Energy, Order No. 202-26-06 (Jan. 26, \n2026), https://www.energy.gov/documents/doe-order-no-202-26-06-pjm). \n478 Id. at 13-14 (citing US Department of Energy, Order No. 202-26-06). \n479 Id. at 13-14. \n480 Id. at 14-15 (noting PJM ICC’s request for a 200 MW threshold in PJM ICC’s \nRequest for Clarification or Rehearing, Docket No. EL25-49-000, et al., at 44)."},{"page":102,"startToken":38237,"endToken":38654,"text":"Docket No. EL25-49-002, et al. \n- 102 - \naddress undue discrimination against Co-Located Loads.  Constellation argues that this \nthreshold will allow a significant number of loads with BTMG to take advantage of \nunjust and unreasonable netting and include backup generation as offsetting BTMG, but \ndeny such treatment to Co-Located Load, despite there being no physical, technical, or \neconomic reason why a netting construct should apply differently for customers with \nBTMG or with Co-Located Generators.  Constellation argues that PJM has not provided \nany explanation for why the proposed threshold is relevant to reducing the reliability and \nresource adequacy risks that large or increasing BTMG may pose to PJM and argues that \nPJM’s justifications for the threshold are unsupported.481   \n Other parties argue that PJM’s proposed threshold is too low.482  \nIndustrials/Amtrak argue that a threshold of at least 200 MW would better capture the \nlarge loads driving reliability and cost-shifting concerns, while maintaining the existing \nretail BTMG netting rules that promote smaller resource adequacy investments, and \navoid economic damage to industrial, institutional, and transportation sectors.  \nIndustrials/Amtrak argue that a 200 MW threshold is also appropriate because PURPA \ndefines small generation for non-cogeneration QFs as 80 MW or smaller, meaning large \ngeneration must be greater than 80 MW.  Industrials/Amtrak also argue that this threshold \nwould simplify the transition process by eliminating most grandfathering issues and \nbolstering resource adequacy and grid efficiency, thereby avoiding inefficient \ntransmission investment.  Industrials/Amtrak argue that a 200 MW threshold would \nrespect the importance of onshoring manufacturing and support Amtrak’s operations, \nbecause Amtrak relies on more than 50 MW of retail BTMG, generated at 25 Hz, to \nprovide energy supply and the only black start capability to the south end of Amtrak’s \nNortheast Corridor traction power system.483   \n Energy Artisans also support a 200 MW materiality threshold.484  Energy Artisans \nargue that, for sites that exceed this higher threshold, the Commission should require \nPJM to use the proposed Interim NITS because it would provide PJM with a “safety \n \n481 Constellation Protest and Comments on Compliance Filing at 9-11. \n482 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 9, 25; \nCrusoe Comments on Compliance Filing at 4; Eastman Protest and Comments on \nCompliance Filing at 6; EDFps Comments on Compliance Filing at 4; Energy Artisans \nProtest of Compliance Filing at 1; DPN Comments on Compliance Filing at 4. \n483 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 9, 25, \n31, 33, 39. \n484 Energy Artisans Protest of Compliance Filing at 2."},{"page":103,"startToken":38654,"endToken":39047,"text":"Docket No. EL25-49-002, et al. \n- 103 - \nswitch” to manage reliability during peak emergencies without forcing expensive \nupgrades or disconnection on industrial users. \n Eastman similarly argues that, if the Commission does not maintain netting for \nBTMG facilities like Eastman’s Kingsport facility, the Commission must establish a \nthreshold of at least 200 MW on a permanent basis.  Eastman explains that its Kingsport \nfacility has generation with a nameplate capacity of 194 MW, but that it cannot withdraw \nthat amount of energy through its interconnection with Kingsport Power and could not \noperate solely on electric power from the grid.  Eastman argues that imposing an \narbitrarily low materiality threshold would eliminate the grid benefits that its BTMG \nfacilities have provided.485 \n Industrials/Amtrak and Eastman argue that setting the threshold too low will \nincrease costs for many existing loads with BTMG and make a lot of existing BTMG \nuneconomic.486  Industrials/Amtrak argue that even if load with BTMG were to have that \ngeneration participate in the PJM markets, there is no guarantee of that generation \nearning sufficient revenue to make up for the loss of netting, especially as transmission \nupgrades may be required to interconnect the generation.  Industrials/Amtrak also argue \nthat setting the threshold too low will force substantial burdens on existing customers to \nbecome Commission-regulated public utilities, secure PJM membership, and undertake \nrelated credit and risk requirements.  Moreover, Industrials/Amtrak argue, a low \nthreshold would remove the incentive to operate efficiently and during stressed system \nconditions, as well as create additional work for PJM staff to study BTMG that must \neither go through the interconnection queue or deactivate.  Industrials/Amtrak contend \nthat retirement of existing BTMG would increase demand and transmission planning \nneeds in the near term, resulting in higher transmission rates.487  Energy Artisans argue \nthat PJM’s proposed 50 MW materiality threshold is an arbitrary cap that ignores the \ncapital-intensive investments made by large-scale industrial facilities.488   \n Industrials/Amtrak argue that BTMG can provide benefits to the transmission \nsystem, including reducing large loads on the system, congestion, and transmission \n \n485 Eastman Protest and Comments on Compliance Filing at 6. \n486 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 7; \nEastman Protest and Comments on Compliance Filing at 6. \n487 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 15, \n25-26, 28. \n488 Energy Artisans Protest of Compliance Filing at 1."},{"page":104,"startToken":39047,"endToken":39432,"text":"Docket No. EL25-49-002, et al. \n- 104 - \nsystem build out, as well as operating during system emergencies.489  EDFps argues that \nBTMG can reduce grid congestion, avoid queue delays, lower Network Upgrade needs, \nand provide economic and community benefits such as tax revenues and jobs.490 \n Crusoe argues that while the 50 MW threshold aligns with PJM’s definition of \nlarge load additions, this threshold is not a bright-line test for what constitutes a \nreliability risk.  Crusoe contends that the materiality threshold should be flexible to \naccount for the fact that Co-Location Arrangements can vary significantly and should be \nscaled in proportion to the load served.  Crusoe argues that a lower threshold risks forcing \nexisting BTMG resources offline during the transition period, which would increase \nburden on the grid by converting currently netted load into Network Load.  Crusoe claims \nthat BTMG arrangements benefit the transmission system by serving load on a \nstreamlined basis, avoiding generator interconnection queue delays, and reducing the \nneed for Network Upgrades.491 \n Energy Artisans also contend that the 50 MW materiality threshold is unduly \ndiscriminatory because it establishes a 50 MW nameplate cap for retail BTMG while \nmaintaining a 3,000 MW regional cap for Non-Retail BTMG.492  In the absence of \ndemonstrated negative impacts from existing BTMG configurations, Energy Artisans \nclaim that the 50 MW materiality threshold is a pretext for cost-shifting. \n EDFps argues that PJM’s proposed 50 MW threshold is arbitrary and will \ndisincentivize large loads from installing their own generation and thereby stifle \ninnovation.  EDFps contends that the threshold will instead incentivize the development \nof smaller loads, as well as segmented loads close in proximity to avoid the threshold, \nleading to inefficient and redundant construction of interconnection facilities.  EDFps \nnotes that the “optimal sizing of Retail BTMG” for an artificial intelligence data center, \nfor example, would be higher than 50 MW and that the threshold would force new large \nloads to develop grid-connected resources instead of BTMG resources.493  EDFps argues \nthat this threshold would result in generation going through the interconnection process \nunnecessarily. \n \n489 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 6. \n490 EDFps Comments on Compliance Filing at 2, 4. \n491 Crusoe Comments on Compliance Filing at 4-5. \n492 Energy Artisans Protest of Compliance Filing at 2. \n493 EDFps Comments on Compliance Filing at 4."},{"page":105,"startToken":39432,"endToken":39803,"text":"Docket No. EL25-49-002, et al. \n- 105 - \n EDFps argues the materiality threshold should instead be 100% of the load size at \nthe electrical location, “combined with operational safeguards and appropriate \ntransmission charges.”494  Specifically, EDFps proposes that retail BTMG larger than           \n50 MW would still be permitted to net generation against load for the purposes of energy \nand capacity market settlements, but would pay transmission and/or distribution network \ncharges on a gross basis.495  \n DPN similarly argues that PJM’s proposal may be too restrictive for digital \ninfrastructure projects, many of which operate at scales well above 50 MW, and that \nbehind-the-meter configurations can provide a viable pathway to speed-to-power.  \nAdditionally, DPN argues, the Commission should not require projects to rely on a \nframework that may compound PJM’s already significant queue and study delays without \ngreater justification.  DPN argues that the Commission should require PJM to better \njustify why 50 MW is the appropriate threshold at this stage and whether a higher \nthreshold, at least on an interim basis, would better accommodate current uncertainty \nwhile PJM and the Commission continue to refine their understanding of large load \nimpacts.496 \n AEU/SEIA claim that PJM’s proposal to require site-located generation to enter \nthe interconnection queue is unjust and unreasonable.  AEU/SEIA assert that PJM \nrequires BTMG arrangements that exceed the materiality threshold or do not qualify for \ngrandfather status to transition to a Co-Location Arrangement, which entails pursuing a \nfull interconnection agreement with PJM.  AEU/SEIA contend that there is no benefit to \nsubjecting these projects to the standard queue process as they do not require \ndeliverability and will rarely trigger Network Upgrades.  AEU/SEIA requests that PJM \nbe encouraged to establish a streamlined, expedited process for resources that do not \nintend to export to the grid, which would allow PJM to maintain visibility while \nminimizing delays for non-exporting resources.497 \nii. \nPJM Proposal to Tie Threshold to Generator \nNameplate Rating \n Several parties urge the Commission to reject PJM’s proposal to base the \nmateriality threshold on the amount of generation that can be netted rather than load, \n \n494 Id. at 1-2. \n495 Id. at 4-5. \n496 DPN Comments on Compliance Filing at 4-5. \n497 AEU/SEIA Limited Protest of Compliance Filing at 11-13."},{"page":106,"startToken":39803,"endToken":40210,"text":"Docket No. EL25-49-002, et al. \n- 106 - \narguing that this proposal is inconsistent with the December Order.498  BTMG Parties \nargue that the scale of the reduction in load (i.e., what PJM considers and plans for versus \nwhat PJM may actually need to serve) determines whether the potential for resource \nadequacy problems and cost shifts are problematic—not the nameplate of the generation \nused to effect the load reduction.499  Similarly, Industrials/Amtrak argue that nameplate \ncapacity does not necessarily reflect the actual capability of BTMG, such as, for example, \na steam system where the generation output is limited by the steam system’s \ncapability.500   \n BTMG Parties further argue that such a nameplate generation-based threshold is \nunjust, unreasonable, and unduly discriminatory because it would also unnecessarily \nconstrain commercial opportunities to serve loads with BTMG without better protecting \nreliability or commensurate reductions in resource adequacy or cost-shift risks and would \ntreat differently BTMGs with similar resource adequacy and cost-shift impacts.  BTMG \nParties argue that accepting PJM’s proposal would violate notice requirements and that \nthe metering, telemetry, and control capabilities already deployed for existing BTMG \nresources demonstrate that BTMG can reliably comply with the operational requirements \nnecessary to implement a netting-based threshold.501 \n BTMG Parties argue that, in the alternative, the Commission should require PJM \nto increase its proposed nameplate rating-based materiality threshold for retail BTMG \neligibility to 200 MW to preserve opportunities for load to realize the commercial benefit \nof sizing nameplate generation above the amount of load that a retail customer seeks to \nnet while still achieving the Commission’s aim of limiting resource adequacy impacts \nand cost-shift concerns.502  \n AEU/SEIA argue that PJM’s proposed threshold is inconsistent with how PJM \nassesses capacity accreditation in the capacity market and lacks the necessary flexibility \nto accommodate resource diversity and hybrid configurations such as storage paired with \nsolar.  AEU/SEIA add that there are a number of reasons that, in a BTMG configuration, \n \n498 BTMG Parties Joint Protest of Compliance Filing at 1, 4-5; Industrials/Amtrak \nJoint Protest and Comments on Compliance Filing at 34-35 (citing December Order,             \n193 FERC ¶ 61,217 at P 179); AEU/SEIA Limited Protest of Compliance Filing at 3.  \nSee also Earthjustice Reply Briefing at 24. \n499 BTMG Parties Joint Protest of Compliance Filing at 6. \n500 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 35. \n501 BTMG Parties Joint Protest of Compliance Filing at 2, 6-12. \n502 Id. at 2, 12-13."},{"page":107,"startToken":40210,"endToken":40591,"text":"Docket No. EL25-49-002, et al. \n- 107 - \nthe generator’s nameplate capacity exceeds the customer’s netting.  AEU/SEIA contend \nthat a reasonable approach would be to permit facilities to exceed 50 MW nameplate \ncapacity provided the customer’s netting is limited to 50 MW, and the facility uses \napproved telemetry and automated system controls.503  Appalachian Voices argues that \nPJM’s compliance filing is unclear as to whether it will apply the 50 MW materiality \nthreshold to all generation or to each individual generator at a single customer site.504   \n Industrials/Amtrak state that, if the Commission opts for a generation-based \nmateriality threshold, they support PJM’s proposal on backup generation.505  \nIndustrials/Amtrak explain that emergency backup generation is often sized similarly to \nother on-site generation to function as a full backup power source and provides additional \ngeneration options in emergency conditions, such as the Department of Energy’s recent \nstatement regarding the operation of private, behind-the-meter generation during Winter \nStorm Fern.506  EDFps argues that the Commission should direct PJM to clarify that \nbattery energy storage systems and hybrid systems functioning in a load-following,             \nnon-exporting capacity manner during a curtailment event qualify under the “backup \ngeneration” exception from the materiality threshold for the revised retail BTMG netting \nrules and can continue to serve the load regardless of their size.507 \niii. \nPJM Proposal to Disqualify Network Customers \nAbove the Materiality Threshold \n Several parties argue that the Commission should allow netting up to the amount \nof the materiality threshold, rather than disqualifying a customer from netting for any \namount of load if its BTMG exceeds the threshold.508  Industrials/Amtrak argue that this \nallowance would be more consistent with the December Order, reduce discrimination \nconcerns, and avoid incentivizing loads to reduce the size of their generation to ensure \n \n503 AEU/SEIA Limited Protest of Compliance Filing at 4-5. \n504 Appalachian Voices Limited Protest of Compliance Filing at 4 (citing \nCompliance Transmittal at 11-12). \n505 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 10. \n506 Id. at 40-41 (citing U.S. Department of Energy, Emergency Order                           \nNo. 202-26-06). \n507 EDFps Comments on Compliance Filing at 8. \n508 Id. at 9, 34; Eastman Protest and Comments on Compliance Filing at 7; Energy \nArtisans Protest of Compliance Filing at 2; EDFps Comments on Compliance Filing at 5."},{"page":108,"startToken":40591,"endToken":40952,"text":"Docket No. EL25-49-002, et al. \n- 108 - \nnetting eligibility.509  Industrials/Amtrak contend that PJM’s proposal would distort \ninvestment decisions, produce outcomes disconnected from actual system needs, harm \nresource adequacy, and harm economic development opportunities in PJM.510   \n Energy Artisans contend that by rejecting a hybrid BTMG and Co-Location \napproach, under which facilities could net up to the materiality threshold, PJM would \nforce large loads off of BTMG status and onto the grid.511  EDFps disagrees with PJM \nthat allowing netting up to the amount of the materiality threshold would lead to \nadditional metering costs, noting that grandfathered entities and those below the threshold \nwould not incur any such costs.  EDFps also argues that it should be up to individual \nentities whether the additional cost for metering is worth exceeding the threshold.  EDFps \nstates that load served by a retail BTMG resource would be required to purchase NFCD \ntransmission service up to the amount covered by the retail BTMG and FCD transmission \nservice for the remainder of the load and could not lean on the system.512  \niv. \nAnswers \n Indicated TOs argue that PJM’s proposed 50 MW materiality threshold strikes the \nappropriate balance between allowing continued use of retail BTMG and limitations to \nensure reliability.  Indicated TOs agree with PJM that 50 MW is reasonable because it \naligns with the PJM Board’s definition of large load additions, preserves existing \ntreatment for smaller and longstanding retail BTMG arrangements, and avoids sweeping \nin retail customers whose grid impacts are comparatively limited.  Indicated TOs argue \nthat PJM reasonably based the threshold on generator size because generator capacity is \nstatic.513 \n Industrials/Amtrak argue that the Indicated TOs fail to substantiate their position \nwith any evidence in support of the 50 MW threshold, and do not address any of the \narguments for a 200 MW or greater threshold.  Industrials/Amtrak contend that load \nunder 200 MW, particularly industrial and institutional load, is not driving current \n \n509 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 9-10. \n510 Id. at 36. \n511 Energy Artisans Protest of Compliance Filing at 2. \n512 EDFps Comments on Compliance Filing 2, 6-7. \n513 Indicated TOs April 24 Answer at 2-3."},{"page":109,"startToken":40952,"endToken":41385,"text":"Docket No. EL25-49-002, et al. \n- 109 - \nreliability challenges.514  Eastman contends that the Indicated TOs’ answer \ninappropriately lumps together all industrial BTMG facilities, ignoring that not all loads \nusing BTMG create reliability and resource adequacy risks.515  BTMG Parties argue that \nIndicated TOs’ defense of a nameplate-based threshold is non-responsive to the BTMG \nParties’ argument because the sole question before the Commission is compliance.516  \nIndicated TOs respond that PJM’s 50 MW threshold is reasonable and should be \naccepted.517  Indicated TOs further argue that the Commission did not preclude a \ngeneration-based threshold, as it provided points of reference based on generator size, not \nthe size of the load.518  Indicated TOs lastly allege that parties conflate the two issues of \nthe materiality threshold and the grandfathering provision, and that the need for an \nadequate grandfathering provision is not a convincing reason to increase the size of the \nmateriality threshold. \nd. \nDetermination \n We accept in part, and reject in part, PJM’s compliance filing with respect to the \nBTMG materiality threshold.  Specifically, we accept as just and reasonable PJM’s \nproposal to set the materiality threshold at 50 MW and to exclude on-site backup power \nfrom that threshold.  However, we reject PJM’s proposal to apply the threshold to the \ncumulative nameplate capacity of generation that is used to serve a retail load served by a \nNetwork Customer located at the same electrical location, rather than to the total amount \nof load that can be netted at that electrical location, because this proposal does not \ncomply with the Commission’s directives in the December Order.519  We thus direct PJM \nto file, within 60 days of the date of this order, a compliance filing to revise its proposed \n \n514 Industrials/Amtrak Answer at 3-4 (citing Industrials/Amtrak Joint Protest and \nComments on Compliance Filing at 25). \n515 Eastman Answer at 2 (citing December Order, 193 FERC ¶ 61,217 at P 107). \n516 BTMG Parties Answer at 2-3. \n517 Indicated TOs June 3 Answer at 3. \n518 Id. at 4. \n519 We therefore reject Proposed Tariff, § I.1 Definitions R-S (Retail Behind The \nMeter Generation) (46.0.0) and § VIII.A 400, Definitions R (Retail Behind The Meter \nGeneration) (7.0.0).  We accept Proposed Tariff, § I.1 Definitions A-B (Behind The \nMeter Generation) (24.0.0); § III.34.2 (Netting of Retail Behind the Meter Generation) \n(1.0.0); § III.34.3 (Netting of Non-Retail Behind The Meter Generation) (2.0.0); § VII.A \n300, Definitions B (Behind The Meter Generation) (2.0.0); and § VIII.A 400,            \nDefinitions B (Behind The Meter Generation) (2.0.0)."},{"page":110,"startToken":41385,"endToken":41862,"text":"Docket No. EL25-49-002, et al. \n- 110 - \ndefinition of Retail BTMG in its Tariff to permit a Network Customer to net up to                 \n50 MW of load that it is serving using BTMG at a particular electrical location. \n In the December Order, the Commission explained the materiality threshold as \nfollows:  “Such a threshold should reduce the reliability and resource adequacy risks \ndiscussed above that large loads may pose to PJM, while also allowing for Network \nCustomers to reduce their transmission charges in a transparent, not unduly \ndiscriminatory fashion.”520  Based on the record here, we find that a threshold of 50 MW \nis just and reasonable and preferable to the 200 MW threshold that some commenters \npropose because a 50 MW threshold will ensure that PJM plans its transmission system \nand procures sufficient capacity resources to serve a greater percentage of the load that, \nin the event that the BTMG that typically serves it is unavailable, PJM would be \nnonetheless obligated to serve.  As such, we find that PJM’s proposed 50 MW materiality \nthreshold is more likely to help maintain resource adequacy and reliability relative to a \nlarger threshold.521  Whereas Constellation argues that PJM’s proposed materiality \nthreshold of 50 MW is too high and unsupported, we agree with PJM that 50 MW strikes \na reasonable balance between a lower threshold, which may restrict netting more than \nnecessary to respond to resource adequacy concerns, and a higher threshold, which would \nfail to address the resource adequacy concerns identified in the December Order.522   \n In response to protesters’ concerns that the proposed materiality threshold of                \n50 MW is too low and will result in significant economic consequences to existing \nBTMG arrangements,523 we note that the Commission addressed this concern in the \n \n520 December Order, 193 FERC ¶ 61,217 at P 221. \n521 See id. P 186 (“We find that PJM’s existing BTMG rules may lead to both \nreliability and resource adequacy risks because PJM, per its Tariff, is obligated to serve \ntransmission customers using BTMG but does not consider such customers in \ntransmission and resource adequacy planning.”). \n522 See Vonage Holdings Corp. v. FCC, 489 F.3d at 1242; ExxonMobil Gas Mktg. \nCo. v. FERC, 297 F.3d 1071, 1085 (D.C. Cir. 2002) (“We are generally ‘unwilling to \nreview line-drawing performed by the Commission unless a petitioner can demonstrate \nthat lines drawn . . . are patently unreasonable, having no relationship to the underlying \nregulatory problem.’”) (citations omitted). \n523 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 27-28 \n(alleging economic damage to retail customers); DPN Comments on Compliance Filing \nat 4 (expressing concern that 50 MW risks foreclosing pathways for digital infrastructure \nprojects “through imposing additional barriers to utilization”); Eastman Protest and \nComments on Compliance Filing at 6 (“the proposed threshold would remove the \neconomic benefits that Eastman has relied on to continue operating its BTMG at the"},{"page":111,"startToken":41862,"endToken":42265,"text":"Docket No. EL25-49-002, et al. \n- 111 - \nDecember Order and established separate mechanisms—a transition period of three years \nfor Network Customers currently using PJM’s retail BTMG netting rules and \ngrandfathering for certain entities in a BTMG arrangement—in recognition of the \npotential impacts for existing BTMG customers of a change in the retail BTMG netting \nrules.524  While we recognize the concerns raised in this record that adopting any \nlimitations on netting may have economic consequences for individual Network \nCustomers, we must balance those concerns against the Commission’s finding that PJM’s \nretail BTMG netting rules are unjust and unreasonable due to the reliability, resource \nadequacy, and cost-shifting concerns they create.525  As discussed above, the materiality \nthreshold primarily serves to reduce reliability and resource adequacy risks that large \nloads may pose to PJM, and we find that PJM’s proposed 50 MW materiality threshold \nstrikes a reasonable balance between mitigating those risks and limiting the costs \nassociated with doing so. \n We decline to require Eligible Customers seeking NITS on behalf of load with \nBTMG to take Interim NITS for load above the materiality threshold, as Energy Artisans \nrequest.  Energy Artisans appear to contemplate taking a combination of Interim NITS \nand NITS at the same Point of Delivery, which is not permitted.526  However, we note \nthat such customers may take Interim NITS, as discussed in Part IV.527   \n We also disagree with arguments that the materiality threshold should be higher to \nensure that BTMG resources have an incentive to operate efficiently.528  This concern \n \nKingsport facilities . . . .”); Energy Artisans Protest of Compliance Filing at 1 (“PJM’s \nproposal to implement a 50 MW ‘Materiality Threshold’ for Retail BTMG is an arbitrary \ncap that ignores the long-term, capital-intensive investment cycles of large-scale \nindustrial facilities.”). \n524 December Order, 193 FERC ¶ 61,217 at PP 222-224. \n525 Id. P 186. \n526 Energy Artisans Protest of Compliance Filing at 2 (“For sites exceeding this \n200 MW threshold, the Commission should direct PJM to utilize the proposed [Interim \nNITS] under the new Part XI of the Tariff.”). \n527 See supra Part IV.C.1.b.i (extending the three new transmission services set \nforth in the December Order to Eligible Customers taking service on behalf of load with \nBTMG that are willing and able to limit their energy withdrawals from the transmission \nsystem under certain conditions). \n528 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 7, 16, \n25, 32."},{"page":112,"startToken":42265,"endToken":42669,"text":"Docket No. EL25-49-002, et al. \n- 112 - \ndoes not overcome the Commission’s finding that large amounts of netted Network Load \npresent reliability and resource adequacy risks.  When BTMG operates during peak or \nemergency conditions, it may enhance resource adequacy in the short term by lowering \nthe demand on the system, but when it fails to operate (which, despite any incentive to \noperate, is possible), the result would be that PJM would have an obligation to serve the \nload that such BTMG typically serves without having planned adequate transmission \nfacilities or procured sufficient capacity resources to fulfill that obligation.  The \nCommission found that risk unjust and unreasonable in the December Order.529  \n We also disagree with Energy Artisans that a 50 MW materiality threshold is \nunduly discriminatory because it establishes a 50 MW cap for Retail BTMG while \nmaintaining a 3,000 MW regional cap for Non-Retail BTMG.530  The materiality \nthreshold and the cap on Non-Retail BTMG function differently—the Non-Retail BTMG \ncap is a region-wide cap on the amount of load that may net using Non-Retail BTMG,531 \nwhereas the materiality threshold for Retail BTMG is on the amount of load that may net \nat a particular electrical location.532   \n We acknowledge EDFps’ concern that a 50 MW materiality threshold on Retail \nBTMG could encourage the development of smaller loads combined with smaller \ngenerators, and force new large loads to develop resources interconnected to the \ntransmission system instead of BTMG resources.533  As the Commission explained in the \nDecember Order, the Commission eliminated retail BTMG netting to prevent large loads \nfrom using the retail BTMG netting rules; the Commission agreed with PJM that \nallowing large loads to net is problematic because such loads do not carry reserves and \nare able to rely on the transmission system when the BTMG is not sufficient to meet the \nload.534  EDFps’ alternative proposal would not remedy this concern because it would \ncontinue to net BTMG for the purposes of capacity market settlements.535 \n \n529 December Order, 193 FERC ¶ 61,217 at P 186. \n530 Energy Artisans Protest of Compliance Filing at 2. \n531 See PJM, Intra-PJM Tariffs, OATT, § III, § 34.3 (Netting of Non-Retail Behind \nThe Meter Generation) (1.0.0). \n532 December Order, 193 FERC ¶ 61,217 at P 221. \n533 EDFps Comments on Compliance Filing at 3-4. \n534 December Order, 193 FERC ¶ 61,217 at P 186. \n535 EDFps Comments on Compliance Filing at 4-5."},{"page":113,"startToken":42669,"endToken":43135,"text":"Docket No. EL25-49-002, et al. \n- 113 - \n Further, we find AEU/SEIA’s assertion that requiring BTMG arrangements that \nexceed the materiality threshold or do not qualify for grandfather status to transition to a \nCo-Location Arrangement, which entails pursuing an interconnection agreement with \nPJM, is unjust and unreasonable is an untimely request for rehearing of the December \nOrder.  In the December Order, the Commission found that PJM’s existing retail BTMG \nnetting rules are unjust and unreasonable because they may lead to both reliability and \nresource adequacy risks in PJM.536  The Commission then directed PJM to revise its retail \nBTMG netting rules to establish a new MW materiality threshold for the amount of load \nat a particular electrical location that Network Customers may net using BTMG and to \nimplement a transition process that includes the ability to grandfather certain entities with \nexisting contracts.537  Because AEU/SEIA’s assertion challenges the Commission’s \nfinding that PJM’s existing retail BTMG netting rules are unjust and unreasonable and \nthe related compliance directives—and not whether PJM complied with those \ndirectives—we find that it is an untimely request for rehearing of the December Order \nand dismiss it on that basis.538  \n However, we agree with protesters that PJM’s proposal to design the materiality \nthreshold for netting based on whether the “generation has a cumulative nameplate rating \nof no greater than 50 MW” fails to comply with the Commission’s directive in the \nDecember Order.  Specifically, the Commission directed PJM to “propose a new MW \nthreshold for the amount of load at a particular electrical location that Network \nCustomers may net by using BTMG.”539  As such, PJM’s proposal to instead apply the \nmateriality threshold to the cumulative nameplate capacity of the generation used by a \nNetwork Customer to serve retail load located at the same electrical location is facially \ninconsistent with the December Order.   \n PJM alleges that its proposal to apply its proposed materiality threshold based on \nthe cumulative nameplate capacity of the generation is consistent with or superior to the \nCommission’s directive to limit reliability and resource adequacy risks.  In particular, \nPJM alleges that its proposal is consistent with the Commission’s points of reference to \nvarious generator sizes, as well as the recognition that BTMG is defined as a generation \nunit rather than a load.  We find PJM’s arguments unpersuasive.  While the Commission \n \n536 December Order, 193 FERC ¶ 61,217 at P 179 (finding that “the existing \nBTMG rules may lead to both reliability and resource adequacy risks because PJM, per \nits Tariff, is obligated to serve transmission customers using BTMG but does not consider \nsuch customers in transmission and resource adequacy planning”). \n537 Id. P 179. \n538 Louisville Gas & Elec. Co., 185 FERC ¶ 61,120, at P 39 (2023). \n539 December Order, 193 FERC ¶ 61,217 at P 221 (emphasis added)."},{"page":114,"startToken":43135,"endToken":43621,"text":"Docket No. EL25-49-002, et al. \n- 114 - \nreferenced examples of generator sizes in the December Order, those examples were in \nreference to an unambiguous threshold for the amount of load that a Network Customer \nmay net.540  In addition, while BTMG is defined as a generation unit, that fact alone is \nnot a reason to propose to apply the materiality threshold to a Network Customer based \non the amount of generation at the same electrical location rather than applying that \nthreshold to the amount of load that may be netted at that location.  Lastly, PJM avers \nthat, whereas load sizes can fluctuate, the nameplate capacity of a generator provides a \nbright line for purposes of qualifying for netting.  This argument too is unpersuasive, \nbecause regardless of whether a Network Customer’s load increases or decreases over \ntime, the 50 MW materiality threshold we approve today makes clear how much of the \nload at a single electrical location a Network Customer may net using BTMG.   \n We also agree with protesters that PJM’s interpretation of the December Order as \nprohibiting any netting when a Network Customer exceeds the materiality threshold is \nincorrect.541  PJM supports its interpretation by pointing to the Commission’s directive in \nthe December Order that PJM “maintain the current BTMG rules for customers that fall \nbelow a new MW materiality threshold,” but PJM reads this language out of context.542  \nRead in full context, the Commission’s replacement rate for BTMG in the December \nOrder only involves setting a new materiality threshold “for the amount of load at a \nparticular electrical location that Network Customers may net by using BTMG,” which \nthe Commission further stated would “allow[] for Network Customers to reduce their \ntransmission charges in a transparent, not unduly discriminatory fashion.”543  Thus, we \nfind that the Commission’s directive in the December Order allows for netting of load up \nto the newly established materiality threshold.  \n Moreover, the Commission expressly states that a materiality threshold “for all \nBTMG should reduce the reliability and resource adequacy risks that large or increasing \n \n540 Id. (“Although we make no finding in this order on a threshold that would be \njust and reasonable, we note as points of reference that PJM requires any generator larger \nthan 10 MW to be individually metered and that the Commission’s definition of a small \ngenerator is 20 MW.”) (footnotes omitted). \n541 Compliance Transmittal 10-11 (“[T]he proposal is based on an interpretation of \nthe compliance directive that demands an ‘all or nothing’ approach to Retail BTMG \nqualification—meaning that a Retail BTMG cannot both net up to a certain threshold but \nstill potentially have generation and load above that threshold which cannot be net”); see \nEastman Protest and Comments on Compliance Filing at 7; Industrials/Amtrak Joint \nProtest and Comments on Compliance Filing at 34. \n542 Compare December Order, 193 FERC ¶ 61,217 at P 179, with id. P 221. \n543 Id. P 221 (emphasis added)."},{"page":115,"startToken":43621,"endToken":44048,"text":"Docket No. EL25-49-002, et al. \n- 115 - \nBTMG may pose to PJM.”544  To use an example similar to that provided by the BTMG \nParties, PJM’s proposal would prohibit a Network Customer serving 50.1 MW of load \nusing BTMG from netting any load, but it would allow a Network Customer serving             \n50 MW of load using BTMG to net all of that 50 MW of load, even though they have \nvirtually identical resource adequacy impacts on the transmission system.545  We find that \nthis outcome would be unduly discriminatory and conflict with the December Order.546  \nWe also note that protesters persuasively dispute PJM’s suggestion that its proposal helps \nload with BTMG avoid incurring significant costs and compliance risks if their \narrangements exceed the materiality threshold.547  We agree with EDFps that Network \nCustomers should decide whether the costs and requirements associated with complying \nwith the revised retail BTMG netting rules are appropriate or cost-effective for their \nbusiness when determining whether to maintain or pursue BTMG arrangements.548   \n In response to EDFps’ request that the Commission clarify that electric storage \nresources and hybrid resources qualify for the back-up exemption, we note that PJM’s \nretail BTMG netting rules do not restrict what resources may qualify as back-up \ngeneration, but instead specify only that the generation must be at the same electrical \nlocation as the retail load and that it can only be used to serve such retail load during \nconditions that may threaten the integrity or reliability of the PJM Region or the regional \npower system.549   \n Accordingly, we direct PJM to file, within 60 days of the date of issuance of this \norder, a compliance filing to revise its Tariff consistent with the Commission’s directive \nin the December Order and our determination here.  Specifically, we reject PJM’s \n \n544 Id. P 179. \n545 BTMG Parties Joint Protest of Compliance Filing at 10. \n546 December Order, 193 FERC ¶ 61,217 at P 221 (“Such a threshold should \nreduce the reliability and resource adequacy risks discussed above that large loads may \npose to PJM, while also allowing for Network Customers to reduce their transmission \ncharges in a transparent, not unduly discriminatory fashion.”).   \n547 See, e.g., BTMG Parties Joint Protest of Compliance Filing at 11 n.20 (“PJM \ndoes not provide any factual support for these assertions, and these statements do not \nmatch BTMG Parties’ experience as developers of BTMG in PJM.”). \n548 EDFps Comments on Compliance Filing at 7. \n549 Id., pt. VIII, Subpart A, section 400 Definitions R (definition of Retail Behind \nthe Meter Generation) (7.0.0)."},{"page":116,"startToken":44048,"endToken":44366,"text":"Docket No. EL25-49-002, et al. \n- 116 - \nproposed definition of Retail Behind The Meter Generation550 and direct PJM to submit a \ncompliance filing modifying the Tariff to instead create a materiality threshold that \nallows Network Customers to net from their Network Load up to 50 MW of load served \nby using BTMG at a single electrical location. \n2. \nGrandfathering and Transition Period \na. \nDecember Order \n The Commission directed PJM to establish a transition period of three years for \nNetwork Customers currently using PJM’s existing retail BTMG netting rules.551  The \nCommission also directed PJM to include in its compliance filing revisions to grandfather \nentities with existing contracts for the specific purpose of effectuating a BTMG \narrangement for the current term remaining under the existing contract.552  The December \nOrder did not direct any changes to Non-Retail BTMG.553 \nb. \nPJM Compliance Filing \n PJM proposes to modify the existing Tariff definition of BTMG and add a new \ndefinition for Retail BTMG to implement a three-year transition period and provide the \nability to grandfather certain entities with existing contracts.554  Specifically, PJM \nproposes that any existing retail BTMG with a contract that was entered into as of the \ndate of the December Order would be permitted to remain eligible to net against Network \nLoads as Retail BTMG irrespective of the materiality threshold through the term of the \ncontract.555  PJM explains that this proposal could include a wide variety of contracts, \nincluding “utility contracts, fuel contracts, maintenance contracts, and more.”556  PJM \n \n550 PJM, Proposed Tariff, § I.1 Definitions R-S (Retail Behind The Meter \nGeneration) (46.0.0) and § VIII.A 400, Definitions R (Retail Behind The Meter \nGeneration) (7.0.0). \n551 December Order, 193 FERC ¶ 61,217 at P 223. \n552 Id. P 224. \n553 Id. P 222. \n554 Compliance Transmittal at 6-7 (citing December Order, 193 FERC ¶ 61,217                \nat P 179). \n555 Id. at 8. \n556 Id."},{"page":117,"startToken":44366,"endToken":44737,"text":"Docket No. EL25-49-002, et al. \n- 117 - \nfurther proposes that this exemption would encompass existing renewal or extension \nrights recognized under any existing contracts to “avoid interference with such reliance \nexpectations upon which investment decisions likely have been made . . . .”557  PJM \nstates that if the Commission accepts its proposal, it will explore with stakeholders \nwhether manual language should be developed to help elaborate on what types of \nagreements may qualify.558 \nc. \nPleadings \ni. \nComments \n AEU/SEIA ask the Commission to reject PJM’s proposal to transition existing \nretail BTMG through December 18, 2028 and instead extend the transition period until \nthe effective date of PJM’s compliance filing to avoid harming projects already \nunderway.  AEU/SEIA allege that setting the grandfathering date earlier than the \neffective date for the new co-location pathways would leave a problematic gap for \nprojects that were moving forward in good faith and exacerbate uncertainty.  AEU/SEIA \nargue that any project “in process” as of the transition date should be eligible for \ngrandfathering if it has made significant progress toward completion though not fully \noperational.559  Otherwise, AEU/SEIA allege, PJM’s proposal will result in significant \nstranded assets.   \n Similarly, BTMG Parties argue that the deadlines for the transition period and \ngrandfathering eligibility will exclude retail customers that recently finalized or will \nimminently finalize projects while providing limited system benefit.  BTMG Parties \nargue that PJM should be required to instead use the date of a Commission order acting \non PJM’s filing, or, at minimum, 180 days from the December 18, 2025 date of the                 \nCo-Location Order (June 16, 2026), as the date from which the grandfathering and \ntransition period run.  BTMG Parties argue that this date would better afford a workable \ntransition for market participants that does not penalize developers for attempting to \ndevelop resources during a historic resource adequacy crisis in PJM.560 \n AEU/SEIA also ask the Commission to clarify that the types of agreements that \nmay qualify for PJM’s proposal include utility interconnection study agreements, \nengineering, procurement, and construction contracts, and any form of binding agreement \n \n557 Id. at 9. \n558 Id. at 9 n.32. \n559 AEU/SEIA Limited Protest of Compliance Filing at 7-9. \n560 BTMG Parties Joint Protest of Compliance Filing at 2-3, 13-16."},{"page":118,"startToken":44737,"endToken":45161,"text":"Docket No. EL25-49-002, et al. \n- 118 - \nbetween the load and the BTMG developer.561  Otherwise, AEU/SEIA warn, developers \nface the risk of delay and additional regulatory burdens that could remove projects \nunderway.   \n Industrials/Amtrak support PJM’s proposal to grandfather existing contracts, \nnoting that BTMG customers operate under diverse agreements, some of which renew \nyear to year, which should be eligible for grandfathering.  Industrials/Amtrak also argue \nthat grandfathering rules and status should be clear, broadly construed, and easily \nconfirmed for existing BTMG customers to ensure stability and regulatory certainty.562 \n AEU/SEIA argue that PJM’s proposal is unjust and unreasonable because it is not \nclear as to whether grandfathering status applies to the site itself or the generator asset.  \nAEU/SEIA suggest that grandfathering the generation while allowing these existing \ncustomers to pursue additional BTMG below the materiality threshold is a logical \nextension of PJM’s observation that additions below the materiality threshold would have \nlittle or no impact.  AEU/SEIA argue that clarifying that customers with grandfathered \nBTMG have a “clean slate” to pursue additional BTMG up to the materiality threshold \nwould also allow existing customers to help address PJM’s resource adequacy and \ninfrastructure needs.  AEU/SEIA contend that many existing customers have neither the \ndesire nor the economic incentive to pursue co-location and that, for smaller projects, \nPJM’s full interconnection process will be too costly and complex.563  Eastman similarly \nrequests that the Commission require PJM’s grandfathering provision to apply to BTMG \nfacilities rather than the service agreement.  Otherwise, Eastman argues, a BTMG facility \ncould lose its grandfathered status if the relevant service agreement is modified because, \nfor example, the facility was modified to become more efficient.564 \n Industrials/Amtrak argue that most BTMG differs from the large loads that the \nCommission addressed in the December Order.  Specifically, Industrials/Amtrak argue \nthat BTMG is not new, is not the cause of the changed circumstances, and does not \npresent the reliability risks posed by large, inverter-based loads.565  Further, \nIndustrials/Amtrak contend, new large loads differ from BTMG in that new large loads \ndo not have substantial cogeneration, do not generally operate large motors that can help \n \n561 AEU/SEIA Limited Protest of Compliance Filing at 7-8. \n562 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 10, 39. \n563 AEU/SEIA Limited Protest of Compliance Filing at 9-11. \n564 Eastman Protest and Comments on Compliance Filing at 7. \n565 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 6-7, \n13; see also Energy Artisans Protest of Compliance Filing at 1."},{"page":119,"startToken":45161,"endToken":45528,"text":"Docket No. EL25-49-002, et al. \n- 119 - \nwith stability on the grid, can turn off and on nearly instantaneously, and can reach sizes \nwell beyond traditional BTMG and the 200 MW threshold proposed by \nIndustrials/Amtrak.  Industrials/Amtrak further claim the December Order “did not find \nthat BTMG rules were unjust and unreasonable as used by manufacturers with \ncogeneration, other QFs (which are size limited under PURPA), or even traditional \n‘large’ loads with BTMG . . . .”566   \nii. \nAnswers \n Indicated TOs argue that PJM’s materiality threshold should be paired with \ngrandfathering provisions that appropriately recognize that customers have relied on \nretail BTMG netting rules and eliminating such rules could cause financial harm.  \nIndicated TOs therefore propose several additions and clarifications to PJM’s proposal.  \nFirst, Indicated TOs argue that grandfathering treatment should extend to all projects that \nare not yet in service and would have been eligible for retail BTMG treatment, but have \nmade “substantial progress towards completion.”567  Indicated TOs also argue that the \nexclusion regarding existing contracts should be construed broadly to cover a wide range \nof contracts and recognition of renewal rights in those contracts.  Indicated TOs argue \nthat existing retail BTMG arrangements that have been physically in service and \noperating for a significant period of time should be grandfathered to avoid disrupting \nlong-standing arrangements.568 \n BTMG Parties and Industrials/Amtrak agree with Indicated TOs that \ngrandfathering should extend to projects that would have been eligible for retail BTMG \ntreatment but for the imposition of the materiality threshold and have made substantial \nprogress toward completion in order to protect the investment-backed expectations of \nPJM customers (and the BTMG developers) and to ensure just and reasonable rates.  \nBTMG Parties and Industrials/Amtrak also argue that the existing contract exception \nshould be construed broadly to cover a wide range of contracts.569  BTMG Parties also \nargue that arrangements that have been physically in service and operating for a \nsignificant period of time should be grandfathered.570 \n \n566 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 14 \n(emphasis in original). \n567 Indicated TOs April 24 Answer at 3. \n568 Id. at 3-4. \n569 BTMG Parties Answer at 2-4; Industrials/Amtrak Answer at 6-7. \n570 BTMG Parties Answer at 4."},{"page":120,"startToken":45528,"endToken":45952,"text":"Docket No. EL25-49-002, et al. \n- 120 - \nd. \nDetermination \n We find that PJM’s proposed Tariff revisions comply with the directives in the \nDecember Order.571   \n First, we find that PJM complies with the directive to revise its Tariff to allow \nNetwork Customers already using the retail BTMG netting rules to continue to do so for \na transition period of three years from the date of issuance of the December Order.572  \nAEU/SEIA and BTMG Parties express concern that such a transition period unfairly \nharms entities that were planning to finalize arrangements in order to use PJM’s retail \nBTMG netting rules.  But these parties did not seek rehearing of the Commission’s \ndecision in the December Order to establish a transition period to minimize the impact on \nexisting BTMG customers.  In that order, the Commission explicitly directed PJM to \n“allow Network Customers already using the BTMG rules to continue to do so for a \ntransition period of three years . . . from the date of issuance of this order.”573  Thus, we \nfind that AEU/SEIA’s and BTMG Parties’ arguments constitute untimely requests for \nrehearing of the December Order.574  However, even if these arguments were properly \nbefore us, AEU/SEIA and BTMG Parties offer no suggested transition period to \nencompass certain potential BTMG customers in a manner that would not be arbitrary.575 \n Second, we find that PJM complies with the directive to revise its Tariff to \ngrandfather entities with existing contracts that effectuate a BTMG arrangement for the \n \n571 See PJM, Proposed Tariff, § I.1 Definitions R-S (Retail Behind The Meter \nGeneration) (46.0.0) and § VIII.A 400, Definitions R (Retail Behind The Meter \nGeneration) (7.0.0). \n572 December Order, 193 FERC ¶ 61,217 at P 223; PJM, Compliance Filing, \nattach. B (defining Retail BTMG to provide “for a transition period through                  \nDecember 18, 2028” for Retail BTMG “used to serve a retail load served by a Network \nCustomer to net load prior to December 18, 2025.”). \n573 December Order, 193 FERC ¶ 61,217 at P 223. \n574 See, e.g., Louisville Gas & Elec. Co., 185 FERC ¶ 61,120 at P 39; ISO New \nEng. Inc., 132 FERC ¶ 61,098, at P 12 (2010) (“The Commission has held that requests \nto alter a compliance filing in a manner that differs from the order requiring the \ncompliance filing constitute a collateral attack on the order requiring the compliance \nfiling.”).  \n575 See BTMG Parties Joint Protest of Compliance Filing at 15 (characterizing a \n“limited class of BTMG developers that were very close to finalizing their projects”)."},{"page":121,"startToken":45952,"endToken":46414,"text":"Docket No. EL25-49-002, et al. \n- 121 - \ncurrent term remaining under the existing contract.576  In response to concerns from \nAEU/SEIA and BTMG Parties, we clarify that the Tariff proposal applies to a contractual \narrangement—for which generation used to serve retail load served by a Network \nCustomer to net load is the subject—“that was in effect as of December 18, 2025.”  \nTherefore, entities with projects that have contractual arrangements “in place, even if \nthey are not yet fully operational” by December 18, 2025 may qualify under the Tariff \nproposal.577  In addition, in response to AEU/SEIA, we clarify that the types of \nagreements that may qualify under PJM’s proposal may include engineering, \nprocurement, and construction contracts, and we encourage PJM, as it states in its \ntransmittal, to explore developing language in its manuals on what other types of \nagreements may qualify.578  Moreover, in response to AEU/SEIA and Eastman, who raise \noverlapping concerns about whether grandfathering applies to the generator, we clarify \nthat it does apply to the generator, as the Tariff proposal on grandfathering reflects.579  In \nfurther response to Eastman, parties to an existing BTMG contract could modify the \nagreement to, for example, make the facilities more efficient—provided that the \nmodification is not prohibited by the existing contract and does not fundamentally alter \nthe contractual arrangement that was in effect as of December 18, 2025.  And in further \nresponse to AEU/SEIA, we clarify that customers with BTMG within the scope of this \ngrandfathering provision may also avail themselves of the new materiality threshold to \nnet up to 50 MW of load served by a Network Customer because this threshold applies to \na particular electrical location. \n3. \nQFs and Cogeneration Facilities \na. \nPJM Compliance Filing \n PJM proposes that the new materiality threshold should not apply to any QF over \n50 MW serving as Retail BTMG as of the date of the December Order.  PJM \n \n576 December Order, 193 FERC ¶ 61,217 at P 224; PJM, Compliance Filing, \nattach. B (defining Retail BTMG to include “any generation used to serve a retail load \nserved by a Network Customer to net load if it is the subject of a contractual arrangement \n(including but not limited to a bilateral agreement or interconnection agreement) that was \nin effect as of December 18, 2025 through the end of the term of such agreement, which \nmay be renewed or extended per the terms of such agreement”). \n577 AEU/SEIA Limited Protest of Compliance Filing at 7. \n578 Compliance Transmittal at 9 n.32. \n579 PJM, Compliance Filing, attach. B (defining Retail BTMG in part to include \n“any generation used to serve a retail load served by a Network Customer to net load if it \nis the subject of a contractual arrangement . . .”)."},{"page":122,"startToken":46414,"endToken":46777,"text":"Docket No. EL25-49-002, et al. \n- 122 - \nacknowledges that the December Order does not reference PURPA, yet because the \nDecember Order was issued against the backdrop of PURPA, “PJM interprets the \nCommission’s [grandfathering] compliance directive as allowing the extension of legacy \ntreatment” to such facilities.  PJM states that some of the QFs impacted by this exemption \nare cogeneration facilities that provide economic and energy efficiency benefits.580  In \nsupport of its proposal, PJM notes that QFs have size limitations and cogeneration QFs \nmust meet efficiency requirements.581  PJM explains that BTMG with existing \ncontractual arrangements or QF status have been in place without any known operational \nissues to date, and so should be allowed to continue netting under their existing \narrangements.582 \nb. \nPleadings \n Industrials/Amtrak argue that QFs should be eligible for retail netting for their full \nload, but the eligibility should not be linked to QF status as of the date of the order.583  \nIndustrials/Amtrak explain that, without retail netting, QFs may be denied the backup \nservice to which they are entitled under PURPA.  Industrials/Amtrak argue that for \ncogeneration QFs, “the BTMG netting construct aligns with their efficient, reliable \nenergy production configurations, matching the intent of Congress and the \n[Commission].”584  Industrials/Amtrak argue that QFs have stronger operational and \nfinancial incentives to operate reliably and efficiently than other generators and must \nmeet certain efficiency standards.  However, Industrials/Amtrak note that many resources \neligible to be QFs have not maintained QF status because PURPA permits the \nCommission to deem certain QFs as having sufficient market access that it removes (for \nthose QFs) the utility’s obligation to purchase excess power generated by the QF.  \nIndustrials/Amtrak explain that many customers with QFs were required by this status \nchange to secure interconnection service and market-based rate authority to sell excess \nenergy into the PJM markets.585  Industrials/Amtrak argue this “history should not limit \n \n580 Compliance Transmittal at 9-10. \n581 Id. at 10 (citing 16 U.S.C. § 824a-3; 18 C.F.R. § 292.204 (2025)). \n582 Id.  \n583 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 8, 17. \n584 Id. at 8. \n585 Id. at 8, 20, 22."},{"page":123,"startToken":46777,"endToken":47170,"text":"Docket No. EL25-49-002, et al. \n- 123 - \nthe ability of retail customers with cogeneration facilities to avail themselves of retail \nBTMG netting for energy production behind the retail meter.”586 \n Industrials/Amtrak argue that the BTMG netting rules ensure QFs have access to \nbackup power to which they are entitled by PURPA, at rates that are not based upon an \nassumption that forced outages or other reductions in electric output by all QFs on the \nsystem will occur simultaneously, during system peak, or both.587  Industrials/Amtrak \ncontend that the FCD or NFCD transmission services would not be sufficient to replace \nnetting, because the FCD transmission service is calculated on the maximum the load \nmight draw from the grid when the QF would only use the system sporadically, and \nNFCD transmission service must be scheduled in advance.  Industrials/Amtrak also argue \nthat these services do not align with the costs or risk profile of cogeneration QFs, such \nthat, without netting, QF customers may lose their ability to manage costs even if their \nload and generation are synchronized or they never rely on transmission services, \ncreating a cost-causation gap.588 \n Industrials/Amtrak argue that exempting QFs is appropriate and consistent with \nthe goals of the December Order because the Commission did not address PURPA.  \nIndustrials/Amtrak also argue that no circumstances have changed with regards to QFs, \nwhich have been operating similarly for decades, and that PJM acknowledges that \nexisting retail BTMG arrangements with QFs have been in place without operational \nissues.  Industrials/Amtrak further argue that QFs contribute to resource adequacy and \nreliability because some are limited in their use of the transmission system by the \nintegration between the load and generation.589 \n Eastman argues that the proposed changes to BTMG netting ignore the operational \nrealities of facilities like Eastman’s Kingsport facility, which uses its on-site electrical \ngeneration not only to provide electric power but also steam necessary for industrial \nprocesses at the facility.  Eastman explains that if the Kingsport facility is unable to \ngenerate power, it also cannot generate steam, which reduces the industrial output and the \nneed for additive power from the grid.  Eastman claims that during periods of grid stress, \nthe Kingsport facility is more likely to support the grid than to create operational \n \n586 Id. at 22. \n587 Id. at 19. \n588 Id. at 20-21. \n589 Id. at 17-19, 21."},{"page":124,"startToken":47170,"endToken":47530,"text":"Docket No. EL25-49-002, et al. \n- 124 - \nconstraints.  Therefore, the Commission should allow BTMG facilities like the Kingsport \nfacility to continue to net.590 \nc. \nAnswer \n Industrials/Amtrak note that many of the customers impacted by the change in \nBTMG netting rules are QFs under PURPA, subject to efficiency standards (and for     \nnon-cogeneration QFs, size limits).591   \nd. \nDetermination \n Consistent with our determination on rehearing,592 PJM must submit a further \ncompliance filing that includes a process to exempt certain cogeneration QFs from the \nnew retail BTMG netting rules if they demonstrate that they are integrated with load such \nthat, when their generating facility trips offline, the load follows.  We therefore reject \nPJM’s compliance filing as it relates to QFs.  Specifically, we reject PJM’s proposal to \nexempt from the materiality threshold all QFs serving as retail BTMG as of the date of \nthe December Order.593  PJM has not demonstrated that all load with BTMG that is either \ndesignated, or eligible to be designated, as a QF is meaningfully distinguishable from \nload with other categories of BTMG for purposes of the concerns and directives \ndiscussed in the December Order. \n In the December Order, the Commission found that PJM’s retail BTMG netting \nrules could create resource adequacy and reliability risks because PJM is obligated to \nserve transmission customers using BTMG but does not consider such customers in \ntransmission and resource adequacy planning.594  The Commission found that PJM’s \nexisting retail BTMG netting rules do not limit the amount of qualifying load that a \nNetwork Customer may net by using BTMG and do not provide any protections against \nthis potential transmission and resource adequacy planning problem or against the costs \nof maintaining sufficient resources to serve these loads being shifted onto other \n \n590 Eastman Protest and Comments on Compliance Filing at 5, 8. \n591 Industrials/Amtrak Answer at 3, 5-6. \n592 See supra Part IV.C.1.c.i. \n593 Compliance Transmittal at 9; PJM, Proposed Tariff, § I.1 Definitions R-S \n(Retail Behind The Meter Generation) (46.0.0) and § VIII.A 400, Definitions R (Retail \nBehind The Meter Generation) (7.0.0). \n594 December Order, 193 FERC ¶ 61,217 at P 186."},{"page":125,"startToken":47530,"endToken":47943,"text":"Docket No. EL25-49-002, et al. \n- 125 - \ncustomers.595  The Commission did not distinguish in its determination between load \nserved by QFs that are BTMG and load served by other categories of BTMG. \n PJM argues that some QFs may have economic benefits and are energy efficient, \nbut PJM does not demonstrate that loads served by QFs that are BTMG do not cause the \nconcerns the Commission discussed in the December Order.596  Nor does PJM \ndemonstrate why these loads are not similarly situated to other loads served by other \ncategories of BTMG.   \n PJM also notes that QFs have size limitations and cogeneration QFs must meet \nefficiency requirements.597  However, the Commission in the December Order directed a \nmateriality threshold because netting a smaller amount of load does not raise the same \nlevel of resource adequacy and reliability concerns as netting above the threshold.598  \nPJM does not demonstrate why the materiality threshold should apply differently to load \nserved by QFs that are BTMG and load served by other categories of BTMG.  Further, \nefficiency requirements are not unique to QFs—other generators may have efficiency \nrequirements for other reasons or meet similar efficiency targets on their own.  PJM has \nnot demonstrated why such requirements are a meaningful consideration in whether to \napply disparate treatment to load served by QFs that are BTMG and load served by other \ncategories of BTMG.  Industrials/Amtrak similarly argue that QFs contribute to resource \nadequacy and reliability because some are limited in their use of the transmission system \ndue to the integration between the load and generation.599  However, as \nIndustrials/Amtrak acknowledge, this is only true of some QFs, and above we have \nrecognized that a particular subgroup, cogeneration QFs, warrant different treatment. \n Industrials/Amtrak also argue that it is not clear whether QFs will have access to \nthe FCD or NFCD transmission services.600  As discussed supra, Eligible Customers \ntaking transmission service on behalf of Co-Located Loads, as well as Eligible Customers \ntaking transmission service on behalf of a load with BTMG, may elect to take FCD \n \n595 Id.  \n596 See Compliance Transmittal at 10 (broadly asserting that BTMG arrangements \nwith QF status have been netting within PJM without known operational issues to date). \n597 Compliance Transmittal at 10 (citing 16 U.S.C. § 824a-3; 18 C.F.R. § 292.204). \n598 December Order, 193 FERC ¶ 61,217 at P 221. \n599 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 18-19, \n21. \n600 Id. at 20."},{"page":126,"startToken":47943,"endToken":48417,"text":"Docket No. EL25-49-002, et al. \n- 126 - \nand/or NFCD transmission services.601  While we acknowledge that Industrials/Amtrak \nalso argue that these new transmission services will not replace netting,602 our \ndetermination herein to allow Eligible Customers taking transmission service on behalf of \nloads with BTMG to take transmission service based on contract demand rather than \nNITS should they so choose could help such Eligible Customers to manage costs if they \ninfrequently rely on transmission service or can reserve needed transmission service in \nadvance (such as when the QF that serves them is on a planned maintenance outage).  \n Industrials/Amtrak argue that without retail netting, QFs may be denied access to \nbackup service at rates that are not based upon an assumption that forced outages or other \nreductions in electric output by all QFs on the system will occur simultaneously, during \nsystem peak, or both, as required by PURPA.  Under the Commission’s PURPA \nregulations, the rates at which a host utility provides backup service must be just and \nreasonable and (1) shall not be based upon an assumption (unless supported by factual \ndata) that forced outages or other reductions in output by all QFs on an electric utility’s \nsystem will occur simultaneously, or during system peak, or both; and (2) shall consider \nthe extent to which scheduled outages of the QF can be usefully coordinated with \nscheduled outages of the utility’s facilities.603  The Commission’s directive in the \nDecember Order to PJM to revise its Retail BTMG netting rules implicates the terms of \nthe Tariff for the provision of transmission service, specifically NITS, not back-up \nservice.  Therefore, Industrials’/Amtrak’s concern regarding backup service appears to \nconflate rates for sales of back-up power and rates for transmission service, rendering the \nconcern misplaced.  As is already the case elsewhere, such as in Midcontinent \nIndependent System Operator, Inc. (MISO),604 NITS transmission rates in PJM, going \nforward, will be based on gross demand during the system peak.  Because this directive \nfrom the December Order has no bearing on the rates at which a host utility provides \nbackup service to QFs, it necessarily does not conflict with the requirement in the \nCommission’s PURPA regulations that the rates for such backup service not assume all \nQFs are on forced outage.   \n \n601 See supra Part IV.B.3.c. \n602 Industrials/Amtrak Joint Protest and Comments on Compliance Filing at 20. \n603 18 C.F.R. § 292.305(c). \n604 See Midwest Indep. Transmission Sys. Operator, Inc., 106 FERC ¶ 61,073,            \nat P 26 (2004) (“[MISO]’s proposal to base Network Service charges for delivery of \nstation power on the basis of coincident-peak output is not consistent with its OATT or \nwith Commission precedent.  Accordingly, [MISO] should include load served by \nbehind-the-meter generation, including station power load met through                                 \non-site self-supply, in Network Load when it charges for Network Service.”)."},{"page":127,"startToken":48417,"endToken":48823,"text":"Docket No. EL25-49-002, et al. \n- 127 - \n With respect to Eastman’s arguments, Eastman appears to reference a \ncogeneration facility, which uses its on-site electrical generation to provide not only \nelectric power but also steam necessary for industrial processes at the facility.605  Because \nwe set aside, in part, the December Order and find that certain cogeneration QFs should \nbe exempted from the replacement rate upon a demonstration that they do not present the \nreliability or resource adequacy concerns discussed in the December Order, Eastman’s \nconcern appears to be addressed.606   \nB. \nTransmission Service \n1. \nDecember Order \n The Commission directed PJM to modify its Tariff to require that the Eligible \nCustomer taking transmission service on behalf of a Co-Located Load takes one of three \ntransmission services:  (1) NITS or Interim NITS, (2) a new FCD transmission service, or \n(3) a new NFCD transmission service.607  The December Order set many of the terms and \nconditions of these services for paper hearing procedures.608  \n The December Order stated that Interim NITS must allow an Eligible Customer \nthat has requested NITS on behalf of a Co-Located Load to take non-firm transmission \nservice that can be interrupted until the Network Upgrades necessary to provide NITS are \ncomplete and the Co-Located Load can be designated as Network Load.609  The \nCommission also found that this service should be temporary, available only to Eligible \nCustomers that have requested NITS on behalf of Co-Located Loads that cannot yet be \nreliably served with NITS and only until the necessary Network Upgrades are completed \nand the Co-Located Load is designated as Network Load.  The December Order further \nstated that Interim NITS would be optional for an Eligible Customer seeking NITS on \nbehalf of a Co-Located Load and only available to the extent PJM determines that it can \nprovide some level of interim service reliably.  The Commission found that Eligible \nCustomers should pay the NITS rate for this service, as well as ancillary services charges \nand charges for black start service, but they will not be charged for generation capacity \nbecause, as interruptible loads, capacity will not be procured on their behalf until such \ntime as the Network Upgrades are in place to serve them.  The Commission clarified that \n \n605 Eastman Protest and Comments on Compliance Filing at 5. \n606 See supra Part IV.C.1.c.i.c. \n607 December Order, 193 FERC ¶ 61,217 at P 193. \n608 Id. P 194. \n609 Id. P 200."},{"page":128,"startToken":48823,"endToken":49193,"text":"Docket No. EL25-49-002, et al. \n- 128 - \nInterim NITS may not be combined with the FCD transmission service or NFCD \ntransmission service. \n With respect to FCD and NFCD transmission services, the Commission found \nthese services should be permanent transmission services available to Eligible Customers \ntaking transmission service on behalf of Co-Located Load.610  The December Order \nprovided that the Co-Located Load must be able and willing to prevent or limit its energy \nwithdrawals and must be separately metered from the associated generator.  The \nDecember Order also stated that Eligible Customers taking transmission service on behalf \nof Co-Located Loads may take a combination of FCD transmission service and NFCD \ntransmission service, but that Eligible Customers taking transmission service on behalf of \nCo-Located Loads that will not withdraw energy from the transmission system must take \nNFCD transmission service at 0 MW.  The Commission also found that Eligible \nCustomers taking either service on behalf of Co-Located Load would be charged for \nregulation and black start services based on gross demand, rather than the reserved \namount of transmission service.611 \n The Commission found that FCD transmission service should have the same \nreservation and curtailment priority as existing firm transmission services at the level of \nthe contract demand and be charged for transmission, ancillary services, and capacity \nbased on the contract demand, with the exception of regulation and black start services.612  \nThe Commission explained that PJM would only have an obligation to plan for the \nNetwork Upgrades necessary to serve Eligible Customers taking this new FCD \ntransmission service on behalf of Co-Located Loads at their contract demand, and that \nPJM would procure capacity for these customers and should charge them based on their \ncontract demand.613  The Commission further found that FCD transmission service \nshould have a minimum term of one year and that PJM should propose an anti-toggling \nmechanism for Eligible Customers switching between FCD and NFCD transmission \nservices.614 \n With respect to NFCD transmission service, the Commission found the service \nshould be available during normal operation and curtailed during emergency operations, \nsimilar to existing non-firm transmission service options.  The Commission found the \n \n610 Id. P 206. \n611 Id. PP 209, 216. \n612 Id. PP 208-209. \n613 Id. P 210. \n614 Id. P 213."},{"page":129,"startToken":49193,"endToken":49495,"text":"Docket No. EL25-49-002, et al. \n- 129 - \nservice should be available for terms ranging from one hour to one month and charged \nbased on as-reserved contract demand.615  The December Order clarified that PJM should \nnot include NFCD transmission service loads in its transmission or resource adequacy \nplanning.616 \n2. \nPJM Compliance Filing \n PJM clarifies that the compliance filing only includes the organizational Tariff \nchanges needed to implement the Commission’s compliance directives regarding creating \nnew transmission services and that the majority of the changes will be determined \nthrough the paper hearing.617  First, PJM submits several “shell” Tariff sheets, including a \nnew Part XI governing the new transmission services, new Attachment F-3A for the \nservice agreement for Eligible Customers taking NITS or Interim NITS on behalf of a \nCo-Located Load, and Attachment F-4 for the service agreement for Eligible Customers \ntaking FCD transmission service or NFCD transmission service on behalf of a                       \nCo-Located Load.618  PJM states that it will file the full text of these sections upon the \nCommission’s decision following the conclusion of the paper hearing.619 \n PJM states that it further proposes modifications to Tariff Part III, governing \nNITS, to clarify that an Eligible Customer taking transmission service on behalf of               \nCo-Located Load must take a transmission service or take steps to disconnect the load \nfrom the transmission system.620  PJM also proposes new language clarifying that an \nEligible Customer taking transmission service on behalf of a Co-Located Load may not \ntake NITS or Interim NITS at the same time as FCD or NFCD transmission service.621  \nFinally, PJM proposes that Co-Located Load that is not served by an Eligible Customer \n \n615 Id. PP 215-216. \n616 Id. P 218. \n617 Compliance Transmittal at 18-19. \n618 Id. at 19-21. \n619 Id. at 21. \n620 Id. at 22. \n621 Id. at 22-23."},{"page":130,"startToken":49495,"endToken":49876,"text":"Docket No. EL25-49-002, et al. \n- 130 - \ntaking transmission service on its behalf “must take all necessary steps to disconnect \nfrom the Transmission System.”622 \n3. \nPleadings \n EDFps supports PJM’s proposed framework for the new transmission services.623  \nConstellation requests modifications to PJM’s proposed Tariff revisions for Interim \nNITS, including:  (1) replacing a load’s “option to seek” Interim NITS with an “option to \ntake”; (2) revising section 28.1 of the Tariff to clarify that Interim NITS is available to \nEligible Customers taking service on behalf of Co-Located Load; and (3) revising  \nsection 29.1 of the Tariff to clarify that the required conditions to receive NITS also \napply to Interim NITS.624 \n Crusoe argues that PJM’s proposal in the paper hearing does not answer critical \nquestions such as how the initial contract demand quantity is determined, whether \ncontract demand quantities can be adjusted as Co-Located Load grows in phases, or how \nPTPS interacts with Co-Location Arrangements where both generation and load sit on the \ndeveloper’s side of the Point of Change in Ownership.625 \n Crusoe supports Interim NITS as a workable, near-term solution to allow load to \noperate on the transmission system while a Co-Located Generator and/or retail BTMG is \nstill being built and interconnected.626  Crusoe claims, however, that PJM’s proposed \napproach appears to treat a new Co-Located Generator as equivalent to a Network \nResource prior to it receiving such status.  On that basis, Crusoe speculates that PJM may \nintend to prevent a Co-Located Generator or retail BTMG from supplying energy to              \nCo-Located Load during a grid curtailment event if that load is being served via Interim \nNITS.  Crusoe contends that this prohibition would create a disincentive to large load \ncustomers using Interim NITS as an option for speedy interconnection.   \n DCC similarly alleges that PJM’s proposal to prohibit customers from relying on a \nCo-Located Generator during curtailment events makes the proposal unworkable and \nwithout practical value.  DCC also requests that PJM define the trigger, scope, and \nsequence of Interim NITS curtailment with respect to the operational limits identified in \n \n622 PJM, Proposed Tariff, Part III (NITS) (4.0.0). \n623 EDFps Comments on Compliance Filing at 8. \n624 Constellation Protest and Comments on Compliance Filing at 18-19. \n625 Crusoe Comments on Compliance Filing at 8. \n626 Id. at 6."},{"page":131,"startToken":49876,"endToken":50222,"text":"Docket No. EL25-49-002, et al. \n- 131 - \nthe study and should not be able to curtail load for unrelated, broader resource adequacy \nconcerns.627 \n Joint Parties argue that the Commission should reject PJM’s proposed Tariff \nrevisions that preclude retail loads served by BTMG from taking the new transmission \nservices and otherwise limit eligibility for the new transmission services to load that is \nconnecting to a generator with interconnection rights.  Joint Parties argue that these retail \nloads are similarly situated to Co-Located Loads in their willingness and ability to limit \ntheir energy withdrawals from the transmission system under certain conditions.628  \n DCC argues that PJM’s proposal does not provide clear timelines for customers to \nbe transitioned from Interim NITS to NITS.629  DCC expresses concern that, without \nclear timelines, Interim NITS could persist indefinitely, creating uncertainty for \ncustomers making long-term investments. \n4. \nAnswers \n Indicated TOs argue that the Commission should reject requests to reject or defer \naction on PJM’s proposal to limit the new transmission services to Co-Located Load, \nbecause, Indicated TOs contend, the December Order limited such services to Eligible \nCustomers taking transmission service on behalf of Co-Located Load.  Indicated TOs \nargue that there is no evidence in the record to support that load-only customers should \nbe entitled to use the new transmission services, which Indicated TOs explain are tied to \ngenerator-specific attributes that load-only customers do not share, such as an associated \ngenerator, separate metering from the generator, and the ability and willingness to \nprevent or limit withdrawals through the Co-Location Arrangement itself.630 \n Indicated TOs state they do not oppose the requested clarification that Interim \nNITS customers be permitted to continue serving on-site load with a Co-Located \nGenerator during a curtailment event, provided that PJM implements safeguards to ensure \nthat any such operation does not result in unreserved use of the transmission system or \notherwise compromise reliability.631 \n \n627 DCC Comments on Compliance Filing at 6-7. \n628 Joint Parties Protest of Compliance Filing at 10. \n629 DCC Comments on Compliance Filing at 8. \n630 Indicated TOs April 24 Answer at 6-7. \n631 Id. at 7-8."},{"page":132,"startToken":50222,"endToken":50668,"text":"Docket No. EL25-49-002, et al. \n- 132 - \n BTMG Parties argue that the record contains ample evidence to support extending \nnew transmission service eligibility to all customers willing and able to limit withdrawals \nfrom the grid, including load-only customers served by BMTG or otherwise able to \nconsume flexibly.632  BTMG Parties contest Indicated TOs’ claim that there is absolutely \nno evidence in the record, noting that the Commission relied on Antora’s comments \nexplaining that its thermal battery technology provides for an inherently flexible,                   \nlow-load factor load, whether or not co-located with generation.633  BTMG Parties argue \nthat the ability to inject to the grid is not required to enable a load to limit withdrawals \nfrom the transmission system, and that the Commission should require PJM to tailor new \ntransmission service eligibility more closely to the Commission’s justification in issuing \nthe Co-Location Order, namely the willingness and ability to limit withdrawals from the \ntransmission system under specified circumstances.634  BTMG Parties contend that if a \nload is able to meet technology-neutral technical requirements to demonstrate reliable \ncurtailment eligibility, it should be allowed to take the new transmission services. \n5. \nDetermination \n We accept PJM’s compliance filing with respect to outlining new transmission \nservices in the Tariff, noting that, as discussed above in Part IV.B.3, we set aside, in part, \nthe December Order and direct PJM to submit further compliance to revise its Tariff to \nextend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions.635  We \nfind that PJM complies with the directive in the December Order to modify its Tariff to \nrequire that an Eligible Customer taking transmission service on behalf of Co-Located \nLoad takes one of three transmission services:  (1) NITS or Interim NITS, (2) a new FCD \n \n632 BTMG Parties Answer at 8.  \n633 Id. at 5-6 (citing December Order, 193 FERC ¶ 61,217 at P 199). \n634 Id. at 8-9. \n635 Specifically, we accept Proposed Tariff, § III.28.1 (Scope of Service) (2.0.0); \n§ III.29.1 (Conditions Precedent for Receiving Service) (4.0.0); § III.29.2 (Application \nProcedures) (4.0.0); § III.31.6 (Annual Load and Resource Information Update) (4.0.0); \nPart XI (Transmission Services Available for Eligible Customers Taking Service on \nBehalf of Co-Located Loads) (0.0.0); attach. F-3A (Service Agreement for Regional \nNetwork Integration Transmission Service And/or Interim Regional Network Integration \nTransmission Service (For Co-Located Load)) (0.0.0); and attach. F-4 (Service \nAgreement For Contract Demand Transmission Service (For Co-Located Load)) (0.0.0)."},{"page":133,"startToken":50668,"endToken":51095,"text":"Docket No. EL25-49-002, et al. \n- 133 - \ntransmission service, or (3) a new NFCD transmission service.636  We acknowledge \nPJM’s statement that it filed on compliance only a limited number of the changes directed \nin the December Order, given the number of issues set to be resolved through the paper \nhearing.   \n However, we reject the Tariff provisions proposing that Co-Located Load that is \nnot served by an Eligible Customer taking transmission service on its behalf “must take \nall necessary steps to disconnect from the Transmission System.”637  We find this \nprovision duplicative of PJM’s proposed changes to Part VIII, Subpart B,                        \nsection 403(A)(1)(r)(iv), which specify that “[t]o the extent that a Project Developer \nseeks to serve Co-Located Load using its generating facility but not identify an Eligible \nCustomer, then the Project Developer must terminate its generating facility’s \ninterconnection to the Transmission System and serve the Co-Located Load fully \nislanded from the Transmission System.” \n We reject Constellation’s request to direct PJM to modify its proposed tariff \nlanguage such that a load has an “option to take” Interim NITS instead of an “option to \nseek” Interim NITS.638  We acknowledge, as Constellation notes, that the December \nOrder stated that “[t]his new interim, non-firm transmission service must allow an \nEligible Customer that has requested NITS on behalf of a Co-Located Load to take             \nnon-firm transmission service that can be interrupted until the Network Upgrades \nnecessary to provide NITS are complete . . . .”639  However, the December Order also \nstated that Interim NITS “would only be available to the extent PJM determines that it \ncan provide some level of interim service reliably.”640  We accept PJM’s proposal and \nclarify that Interim NITS is an option but not a right, as it is available to an Eligible \nCustomer taking transmission service on behalf of Co-Located Load only to the extent \nthat PJM determines it can be provided reliably.  Constellation appears to request that the \nCommission require PJM to provide Interim NITS regardless of this reliability limitation, \nwhich would not be just and reasonable or consistent with the December Order.  We \nreject Constellation’s other requested clarifications on the required conditions to receive \nInterim NITS as not required for PJM to comply with the December Order.  Further, \nbecause PJM proposes to create a new Tariff section governing Interim NITS, \n \n636 December Order, 193 FERC ¶ 61,217 at P 193. \n637 PJM, Proposed Tariff, Part III (General) (4.0.0). \n638 Constellation Protest and Comments on Compliance Filing at 18-19. \n639 December Order, 193 FERC ¶ 61,217 at P 200. \n640 Id."},{"page":134,"startToken":51095,"endToken":51523,"text":"Docket No. EL25-49-002, et al. \n- 134 - \nConstellation has not shown why it is necessary to add details regarding Interim NITS to \nthe existing Tariff sections addressing NITS.641 \n In its comments on the compliance filing, Crusoe makes several misplaced \narguments about the illustrative tariff PJM submitted in the paper hearing.642  Crusoe \nargues that PJM’s illustrative tariff does not explain how the initial contract demand \nquantity is determined.  It is not clear what Crusoe means, given that the purpose of FCD \nand NFCD transmission services is to allow an Eligible Customer taking service on \nbehalf of Co-Located Load to request a specific contracted amount of transmission \nservice.643  The initial level of transmission service will thus be determined in the first \ninstance by the requesting Eligible Customer.  PJM will evaluate those requests pursuant \nto its study process, which we address below.644  Crusoe also argues that PJM does not \nexplain how PTPS interacts with Co-Location Arrangements where both the generator \nand load sit on the Interconnection Customer’s side of the Point of Change in Ownership.  \nHowever, this arrangement appears to refer to PJM’s proposed change to the definition of \nCo-Located Load, which we reject herein.645   \n Crusoe’s request for clarification as to how phased-in load will be treated under \nFCD and NFCD transmission services is addressed below in Part VI.A.2.  Crusoe and \nDCC also make arguments about curtailment rules or procedures for Eligible Customers \ntaking Interim NITS on behalf of Co-Located Load, and that issue is addressed below in \nPart VI.G.  Finally, comments urging the Commission to reject PJM’s compliance filing \nfor failing to make the new transmission services available to Eligible Customers on \nbehalf of non-Co-Located Loads are untimely requests for rehearing.  These commenters \nargue for a modification of the December Order, not that PJM has failed to comply with \nit.646  However, we address related arguments on rehearing of the December Order above \nin Parts IV.B.3 and IV.C.1.b.ii. \n \n641 Compliance Transmittal at 19-20. \n642 Crusoe Comments on Compliance Filing at 8.  To accompany its initial brief on \npaper hearing, PJM submitted an illustrative tariff with proposed rates, terms, and \nconditions for the three new transmission services.   \n643 See December Order, 193 FERC ¶ 61,217 at PP 208, 216. \n644 See infra Part VI.A.3.  \n645 See infra Part V.D.5.a. \n646 See, e.g., ISO New Eng. Inc., 132 FERC ¶ 61,098 at P 12 (“The Commission \nhas held that requests to alter a compliance filing in a manner that differs from the order"},{"page":135,"startToken":51523,"endToken":51904,"text":"Docket No. EL25-49-002, et al. \n- 135 - \n Finally, we note that DCC’s concerns regarding the terms and conditions of \nInterim NITS are misplaced arguments about the illustrative tariff PJM submitted in the \npaper hearing and are discussed in Part VI.H. \nC. \nNecessary Studies \n1. \nDecember Order \n The Commission directed PJM to revise the Tariff to clarify that an existing \nInterconnection Customer seeking to modify its ISA or GIA to allow its generator to \nserve Co-Located Load, including to reflect any reduction in its CIRs, must follow the \nNecessary Study process to effectuate such Co-Location Arrangement.647  In addition, the \nCommission directed PJM to add to the Tariff a description of the scope of the analysis \nthat it will perform as part of the Necessary Study process when an Interconnection \nCustomer seeks to use its existing generator to serve Co-Located Load, consistent with \nPJM’s discussion of how it conducts necessary studies associated with Interconnection \nCustomers seeking to amend their ISAs or GIAs to use existing generators to serve              \nCo-Located Load, including to reflect any reduction in CIRs.  The Commission found \nthat PJM must include a description of the information that the Interconnection Customer \nmust provide about the Co-Located Load for the purposes of the Necessary Study, and \nthat the Necessary Study process must assess any special protection scheme that is part of \na Co-Location Arrangement.648 \n The Commission directed PJM to revise the Tariff to indicate that the \nInterconnection Customer will be responsible for the costs of any modifications or \nNetwork Upgrades that are needed as a result of PJM’s study of the change to the ISA or \nGIA to allow the existing generator to serve Co-Located Load, including to reflect any \nreduction in CIRs, inclusive of all necessary Network Upgrades.649  The Commission \nfound that the Tariff should make clear that an existing generator may not commence \nservice to a Co-Located Load until all required Network Upgrades, special protection \nschemes, and metering are in service.650  Finally, the Commission clarified that an \nexisting generator may not begin serving Co-Located Load that is not Network Load until \n \nrequiring the compliance filing constitute a collateral attack on the order requiring the \ncompliance filing.”).  \n647 December Order, 193 FERC ¶ 61,217 at P 226. \n648 Id. P 227. \n649 Id. P 228. \n650 Id."},{"page":136,"startToken":51904,"endToken":52238,"text":"Docket No. EL25-49-002, et al. \n- 136 - \nit has delisted its CIRs for the portion of the generator to be designated to serve any                \nCo-Located Load that is not receiving NITS.651 \n2. \nPJM Compliance Filing \n PJM states that it proposes changes to Parts III and VIII of the Tariff to comply \nwith the Commission’s directives regarding the Necessary Study process for existing \nInterconnection Customers, including clarifying that customers must enter into a \nNecessary Study Agreement with PJM.652  PJM also proposes to require customers to \nprovide PJM with all information needed to perform the Necessary Studies, which PJM \nproposes to detail in the PJM manuals.653  PJM states that a Project Developer may not \nmake changes to its facilities until it has completed the Necessary Study process and the \namended GIA is effective.  PJM proposes that the Tariff state that Necessary Studies to \nbe performed include thermal, short circuit, and stability studies under various seasonal \nand load conditions, as detailed in the PJM manuals, and assess any necessary control \ntechnologies and protection systems required.  Lastly, PJM states that the Tariff will \nrequire the Project Developer to be responsible for the cost of any modifications or \nNetwork Upgrades necessary as a result of an Interconnection Customer’s decision to \nserve the Co-Located Load.654 \n PJM clarifies that these changes apply to all existing interconnection customers, \nregardless of whether they have effective interconnection agreements issued pursuant to \nParts IV, VI, VII, or VIII of the Tariff.655  PJM states that, should an interconnection \ncustomer not have a three-party interconnection agreement involving PJM, the customer \nwould need to first convert to a three-party agreement before following the Necessary \nStudy process. \n3. \nPleadings \n A number of parties have concerns with PJM’s compliance filing.  Several parties \nprotest PJM’s compliance filing and urge the Commission to require PJM to establish \n \n651 Id. P 230. \n652 Compliance Transmittal at 24-25. \n653 Id. at 25 (citing December Order, 193 FERC ¶ 61,217 at P 227). \n654 Id. at 25-28. \n655 Id. at 24-25."},{"page":137,"startToken":52238,"endToken":52635,"text":"Docket No. EL25-49-002, et al. \n- 137 - \ndeadlines to complete the Necessary Study process.656  Constellation urges the \nCommission to direct PJM to detail the specific provisions in the PJM manuals to which \nthe proposed Tariff language refers because it does not specify whether PJM is proposing \nto use the existing Necessary Study process or a new process, and the existing \nrequirements set forth in PJM Manual 14C do not specifically reference the studies to be \nperformed.  Crusoe and Constellation urge the Commission to direct PJM to revise the \nproposed Tariff’s scope of the analysis to explicitly relate to reliability impacts only, \nrather than impacts generally.657  Crusoe contends that PJM should create a clear, \npublished standard for what triggers the Necessary Study process. \n Energy Artisans argue that PJM’s proposed Necessary Study requirements will \nforce industrial users to fund thermal, short circuit, and stability studies and bear the costs \nof Network Upgrades, control technologies and protection systems, and redundant \nmetering equipment identified during these studies.  Energy Artisans allege that these \nrequirements will force many industrial facilities to cease operations, which will lead to \nhigher Network Loads and exacerbate resource adequacy issues in PJM.658   \n Vistra and Constellation request that PJM clarify how the proposed Tariff \nrevisions describing the Necessary Study process would apply to interconnection \ncustomers who have already submitted requests and are undergoing studies.  \nConstellation and Vistra assert that Co-Location Arrangements will face significant \ndelays if they must reenter the Necessary Study process.659  Vistra maintains that PJM’s \nfailure to include a transition mechanism is an unjustified departure from the \nCommission’s approach to interconnection reform, in which the Commission has \nregularly required transition mechanisms to avoid disruption and stranded investments.660  \nConstellation proposes to clarify that Project Developers with existing requests for \nNecessary Studies for Co-Location Arrangements will be allowed to rely on the results of \nthose studies to the extent relevant in light of the transmission service the Eligible \n \n656 Constellation Protest and Comments on Compliance Filing at 12, 17; DCC \nComments on Compliance Filing at 7; Crusoe Comments on Compliance Filing at 9. \n657 Constellation Protest and Comments on Compliance Filing at 12-14; Crusoe \nComments on Compliance Filing at 9. \n658 Energy Artisans Protest of Compliance Filing at 1-2. \n659 Constellation Protest and Comments on Compliance Filing at 15; Vistra Protest \nof Compliance Filing at 4, 6-8. \n660 Vistra Protest of Compliance Filing at 4-5."},{"page":138,"startToken":52635,"endToken":53029,"text":"Docket No. EL25-49-002, et al. \n- 138 - \nCustomer plans to request on behalf of the Co-Located Load.661  Constellation and Vistra \nargue that requiring interconnection customers to restart the process would be \ninconsistent with the filed-rate doctrine and rule against retroactive ratemaking and \nwould effectively penalize parties for failing to comply with rules that did not exist at the \ntime they acted.662   \n Vistra contends that PJM neither justifies its proposal to require interconnection \ncustomers with older interconnection agreements to enter into the new pro forma GIA \nnor shows how this proposal is consistent with the Commission’s directives.  Vistra \nsuggests that this proposal is unrelated to the Commission’s compliance directives and \nrequests clarity about when the interconnection customer needs to enter into the new GIA \nin the Necessary Study process.  Vistra also asserts that PJM’s proposal could result in \ndisputes about whether and how provisions in the updated pro forma GIA apply to older \ngenerators, disrupting long-standing Commission precedent.  Separately, Vistra indicates \nthat, because PJM locates Necessary Study revisions in Part VIII, which applies to New \nService Requests on or after October 1, 2021, it is unclear whether interconnection \ncustomers that entered the interconnection process before that date may use the \nNecessary Study process.663 \n Joint Parties argue that PJM should be required to clarify that an existing \ninterconnection customer can nominate a joint withdrawal limit in the Necessary Study \nprocess.664  Joint Parties argue that this clarification is necessary to realize the December \nOrder’s stated intent of ensuring that Co-Located Loads do not pay for services that they \ndo not use and do not trigger Network Upgrades that they do not need.665  Joint Parties \nargue that PJM’s proposed Tariff revisions appear to remain silent as to how it will treat \nenergy withdrawals in studying Co-Located Load interconnection requests.  Joint Parties \nstate that they seek modest clarifications from PJM that, to the extent PJM performs \ninterconnection study steps involving withdrawal assumptions for Co-Located Loads, an \nenergy storage interconnection customer will be able to specify limits to the injection and \n \n661 Constellation Protest and Comments on Compliance Filing at 14-15. \n662 Id. at 15; Vistra Protest of Compliance Filing at 4, 6. \n663 Vistra Protest of Compliance Filing at 14-16. \n664 Joint Parties Protest of Compliance Filing at 4-6.  See also Earthjustice Reply \nBrief at 22. \n665 Joint Parties Protest of Compliance Filing at 4-5."},{"page":139,"startToken":53029,"endToken":53431,"text":"Docket No. EL25-49-002, et al. \n- 139 - \nwithdrawal rights reflecting the proposed integration of the storage and Co-Located Load \nfacilities.666   \n Parties argue that PJM’s proposal for delisting CIRs may be unjust, unreasonable, \nunduly discriminatory, or inconsistent with the Commission’s directives in the             \nDecember Order.  Vistra claims that PJM’s proposal would require existing generators to \nprovide PJM with the amount of reduction to CIRs to facilitate the Co-Located Load \nconfiguration, which Vistra argues is vague and potentially overbroad because it could be \nread to require that generators include in their CIR reduction any portion of a facility that \nwill ever provide power to a Co-Located Load.  Vistra and DCC express concern that \nPJM’s proposal could require generators to delist more CIRs than necessary.667  Vistra \nfurther contends that allowing secondary units to provide occasional, interruptible service \nto Co-Located Load and to retain their CIRs would be consistent with the Tariff.  Vistra \nand Constellation argue that capacity resources that serve Co-Located Load on an \ninterruptible basis should not be required to delist CIRs.668  Vistra presents an additional \nconcern with PJM’s proposal for reducing CIRs, namely, that PJM fails to explain how it \nwill assess the impact of the reduction of CIRs.669  Vistra alleges that because PJM’s \nproposal is vague on this point, PJM could, for example, improperly incorporate resource \nadequacy considerations into its Necessary Study process.  \n4. \nDetermination \n We find that PJM’s proposed revisions to its Necessary Study process partially \ncomply with the directives set forth in the December Order and therefore accept the \nTariff revisions in part, reject them in part, and direct a further compliance filing as \ndiscussed below. \n We accept PJM’s proposed revisions to Part VIII, Subpart A, section 401 and             \nPart IX, Subpart G of the Tariff to comply with the directives in the December Order by: \n(1) adding a description of the scope of the analysis that it will perform as part of the \nNecessary Study process when an Interconnection Customer seeks to use its existing \ngenerator to serve Co-Located Load; (2) requiring the Interconnection Customer to be \nresponsible for the costs of any modifications or Network Upgrades that are needed as a \n \n666 Id. at 5. \n667 Vistra Protest of Compliance Filing at 8-10; DCC Comments on Compliance \nFiling at 7. \n668 Vistra Protest of Compliance Filing at 11; Constellation Protest and Comments \non Compliance Filing at 19. \n669 Vistra Protest of Compliance Filing at 12."},{"page":140,"startToken":53431,"endToken":53920,"text":"Docket No. EL25-49-002, et al. \n- 140 - \nresult of PJM’s study of the change to the ISA or GIA to allow the existing generator to \nserve Co-Located Load, including to reflect any reduction in CIRs, inclusive of all \nnecessary Network Upgrades; and (3) clarifying that an existing generator may not \ncommence service to a Co-Located Load until all required Network Upgrades, special \nprotection schemes, and metering are in service.670  We also accept PJM’s proposed \nrevisions to Part IX, Subpart A, Form of Application and Studies Agreement to facilitate \nPJM’s collection of the information necessary to perform requested Necessary Studies.671  \nHowever, with respect to Constellation’s argument that PJM’s proposed Tariff revisions \nmay lack clarity, we direct PJM to specify in its compliance filing what types of \nadditional detail about the studies will be available in the PJM manuals.   \n We also note in response to Constellation that, per the December Order, PJM’s \nproposal seeks to clarify the existing Necessary Study process, not create a new one.672  \nWhile parties request that the Commission establish deadlines for the Necessary Study \nprocess, we note the December Order did not include any such requirement, and our \nreview of these proposed Tariff revisions is limited to whether PJM complies with the \ndirectives in the December Order.673  In response to parties’ requests regarding the trigger \nand scope of the Necessary Study process, we note that the Commission in the December \nOrder directed PJM to clarify its study procedures for an Interconnection Customer that \nwill use its generator to serve Co-Located Load but did not otherwise direct changes to \nthe trigger or scope of the Necessary Study process.  Per the Tariff, the scope of the \nNecessary Study is to determine whether planned modifications to an Interconnection \nCustomer’s facilities “will have a permanent material impact on the Transmission System \nand to identify the additions, modifications, or replacements to the Transmission System, \n \n670 December Order, 193 FERC ¶ 61,217 at PP 227-228.  We also accept the \nconforming edit to the definition of Necessary Study in Proposed Tariff, § VII.A 300, \nDefinitions N (3.0.0) and § VIII.A 400, Definitions N (4.0.0). \n671 Compliance Transmittal at 27; PJM, Proposed Tariff, pt. IX, subpt. A, (Form of \nApplication and Studies Agreement) (4.0.0). \n672 See Compliance Transmittal at 25 (“The thrust of PJM’s proposed revisions \nrequire any Existing Interconnection Customer that seeks to serve Co-Located Load to \nfollow a clarified necessary study process detailed in Part VIII of the Tariff and the \nrelated Form of Necessary Study Agreement set forth in Tariff, Part IX, Subpart G.”). \n673 See, e.g., PJM Interconnection LLC, 119 FERC ¶ 61,179, at P 12 (2007) (“The \npurpose of a compliance filing is to make the directed changes and the Commission’s \nfocus in reviewing them is whether they comply with the Commission’s previously stated \ndirectives.”) (citing AES Huntington Beach, LLC, 111 FERC ¶ 61,079, at P 60 & n.25 \n(2005))."},{"page":141,"startToken":53920,"endToken":54349,"text":"Docket No. EL25-49-002, et al. \n- 141 - \nif any, that are necessary, in accordance with Good Utility Practice, and/or to maintain \ncompliance with Applicable Laws and Regulations or Applicable Standards, to \naccommodate the planned modifications.”674  Regarding Joint Parties’ requests regarding \nstudy processes for Co-Located Loads paired with electric storage resources, we note that \nthe December Order did not address or otherwise direct changes as to any generator \ninterconnection study procedures for such resources.  \n We reject in part PJM’s proposed revisions to Part III of its Tariff regarding the \nrequirement for Interconnection Customers with effective ISAs pursuant to Part VI of the \nTariff or effective GIAs pursuant to Part VII of the Tariff to enter into a new GIA \npursuant to Part VIII of the Tariff and the pro forma GIA in Part IX, Subpart B.  We \nagree with Vistra that such a requirement is inconsistent with the Commission’s \nrecognition in the December Order that existing Interconnection Customers that seek to \nmodify their ISAs or GIAs must follow the Necessary Study process to effectuate a              \nCo-Location Arrangement.675  Interconnection Customers with effective ISAs or GIAs \nmust be able to modify those agreements and undergo the Necessary Study process \nwithout entering into new GIAs.   \n We also agree with protesters that PJM’s proposed revisions lack clarity with \nrespect to how they apply to Interconnection Customers that have already executed \nNecessary Study Agreements and for which PJM has already completed Necessary \nStudies.676  The Commission found in the December Order that the Necessary Study \nprocess lacked sufficient clarity and directed PJM to add the scope of the analysis it \nperforms as part of the Necessary Study process to its Tariff.677  However, the \nCommission did not direct changes to the scope of the study, and PJM does not otherwise \ndemonstrate why Interconnection Customers seeking to serve Co-Located Load cannot \n \n674 PJM, Intra-PJM Tariffs, pt. VIII.A, § 400 (Definitions N) (2.0.0) (definition of \nNecessary Study). \n675 December Order, 193 FERC ¶ 61,217 at P 226 (“[W]e direct PJM to submit, \nwithin 60 days of the date of issuance of this order, a compliance filing to revise the \nTariff to clarify that an existing Interconnection Customer seeking to modify its ISA or \nGIA to allow its generating facility to serve Co-Located Load, including to reflect any \nreduction in its CIRs, must follow the necessary study process to effectuate such          \nCo-Location Arrangement.”) (emphasis added). \n676 Constellation Protest and Comments on Compliance Filing at 15; Vistra Protest \nof Compliance Filing at 4, 6. \n677 December Order, 193 FERC ¶ 61,217 at P 227."},{"page":142,"startToken":54349,"endToken":54813,"text":"Docket No. EL25-49-002, et al. \n- 142 - \nrely on the results of Necessary Studies that have already been performed if the scope of \nthe study has not changed.   \n For these reasons, we direct PJM to submit a compliance filing within 60 days of \nthe date of issuance of this order to remove the requirement for Interconnection \nCustomers with existing ISAs pursuant to Part VI of the Tariff and GIAs pursuant to          \nPart VII of the Tariff to enter into a new pro forma GIA.  We recognize that removing the \nrequirement for Interconnection Customers with existing ISAs pursuant to Part VI of the \nTariff and GIAs pursuant to Part VII of the Tariff to enter into a new pro forma GIA will \nnecessitate duplicating the appropriate Necessary Study Tariff provisions (Part VIII, \nSubpart A, section 401.H.3) in those Tariff sections, and therefore we direct PJM to \ninclude these Tariff revisions in its compliance filing.  We find that this directive will \nensure that Interconnection Customers with effective ISAs or GIAs will not be required \nto enter into new GIAs if they seek to modify their ISA or GIA to allow their generator to \nserve Co-Located Load.   \n We also direct PJM to explain in its compliance filing how its changes ensure the \nprohibition on Interconnection Customers serving Co-Located Loads from existing \ngenerators until all required Network Upgrades, necessary control technologies and/or \nprotection systems, and metering identified as necessary are complete and in service, \napplies to Interconnection Customers with currently effective GIAs, ISAs, and Necessary \nStudy Agreements, in addition to Interconnection Customers seeking new Necessary \nStudy Agreements and GIAs. \n In response to Constellation’s request that the Commission clarify that \nInterconnection Customers with existing requests for Necessary Studies for Co-Location \nArrangements may rely on the results of those studies to the extent relevant in light of the \ntransmission service the associated Eligible Customer plans to request on behalf of the \nCo-Located Load, we clarify that the studies applicable to a transmission service request \nfor one of the new transmission services are distinct from the Necessary Study process, \nwhich studies the modification of a generator interconnection.  If an Eligible Customer \nseeks to take one of the new transmission services on behalf of Co-Located Load, it must \nrequest transmission service and follow the appropriate transmission service study \nprocedures as directed in this order. \n With respect to Energy Artisans’ argument that requiring industrial users to bear \nthe costs of modifications or Network Upgrades will force industrial facilities to cease \noperations and exacerbate resource adequacy issues in PJM, we dismiss this argument as \nan untimely request for rehearing of the December Order’s finding that PJM’s existing \nretail BTMG netting rules were no longer just and reasonable.678  We reiterate that the \n \n678 Id. P 221; see supra P 232 & n.585."},{"page":143,"startToken":54813,"endToken":55151,"text":"Docket No. EL25-49-002, et al. \n- 143 - \nrequirement to be responsible for costs of modifications or Network Upgrades applies \nonly to Interconnection Customers that seek to modify their ISA or GIA to allow their \ngenerator to serve Co-Located Load, and this is a clarification of existing Tariff \nprovisions in the pro forma ISA and GIA, as explained above.679  Interconnection \nCustomers may choose to maintain their current ISAs or GIAs with no modifications, and \nInterconnection Customers who do not wish to bear these costs may choose not to pursue \nCo-Location Arrangements.   \n Consistent with our above discussion, we disagree with Vistra and Constellation \nthat capacity resources should not have to reduce their CIRs to serve Co-Located Load.680  \nWe also reject without prejudice PJM’s proposed Tariff, Part IX, Subpart G, Form of \nNecessary Studies Agreement, because PJM has proposed changes to the Cost \nResponsibility section without explanation.681   \nD. \nOther \n1. \nDecember Order \na. \nDefinition of Co-Located Load \n In the December Order, the Commission directed PJM to adopt the definition of \nCo-Located Load specified in the order:  “a configuration that refers to end-use customer \nload that is physically connected to the facilities of an existing or planned Customer \nFacility on the Interconnection Customer’s side of the Point of Interconnection to the \nPJM Transmission System.”682 \nb. \nGeneration Interconnection Procedures, pro forma GIA, \nand Common Service Provisions \n The Commission also directed PJM to revise its Tariff, VIII, Subpart B,              \nsection 403 - Application Rules to add to the list of requirements for a New Service \n \n679 Tariff, Intra-PJM Tariffs, OATT, Attachment O, Appendix 2, § 3.4(b) \nModification Costs (0.0.0); id., Part IX.B, Appendix 2, § 3.4(b) Modification Costs \n(2.0.0). \n680 See supra Part IV.C.2.a.iii. \n681 PJM, Proposed Tariff, pt. IX, subpt. G (Form of Necessary Studies Agreement) \n(3.0.0), § 15 (Cost Responsibility).  Specifically, PJM proposes to raise the initial deposit \nfor the Necessary Studies from $25,000 to $50,000. \n682 December Order, 193 FERC ¶ 61,217 at P 164."},{"page":144,"startToken":55151,"endToken":55506,"text":"Docket No. EL25-49-002, et al. \n- 144 - \nRequest that an Interconnection Customer who will use its generator to serve Co-Located \nLoad must specify an Eligible Customer who will take transmission service on behalf of \nthe Co-Located Load.683  The Commission further directed PJM to submit revisions to \nthe generation interconnection procedures to specify any operational procedures or data \nexchange requirements that PJM deems necessary for Co-Location Arrangements to \nremedy the Tariff deficiencies, such as unique operational procedures and data exchange \nrequirements.684  The Commission noted that these revisions would establish a \nrequirement in the Tariff for the Eligible Customer to be charged for transmission and \nancillary services that the Eligible Customer must take on behalf of the Co-Located Load.  \nThe Commission clarified that, should an Interconnection Customer wish to serve                  \nCo-Located Load using its generator but not identify an Eligible Customer, then the \nInterconnection Customer may take steps to terminate its generator’s interconnection to \nthe PJM transmission system and serve the Co-Located Load fully islanded from PJM’s \ntransmission system.685 \n The Commission also directed revisions to the Tariff, Part IX, Subpart B GIA to \nspecify that an Interconnection Customer that will use its generator to serve Co-Located \nLoad must specify an Eligible Customer that will take transmission service on behalf of \nthe Co-Located Load.686  The Commission directed PJM to add a new provision to Part I, \nCommon Service Provisions, of the Tariff that requires Interconnection Customers with \nISAs or GIAs executed, or requested to be filed unexecuted, prior to the effective date of \nthe revised generation interconnection procedures and pro forma GIA directed in this \norder that wish to add Co-Located Load or are currently serving Co-Located Load to \npublicly notify PJM of that addition and identify the Eligible Customer that will take \ntransmission service on behalf of that Co-Located Load.   \n2. \nPJM Compliance Filing \na. \nDefinition of Co-Located Load \n On April 16, 2026, the Commission issued an order rejecting the portion of PJM’s \nfirst compliance filing proposing to define Co-Located Load in a manner that deviated \n \n683 Id. P 188.  \n684 Id. P 188 & n.405. \n685 Id. P 189. \n686 Id. P 190."},{"page":145,"startToken":55506,"endToken":55861,"text":"Docket No. EL25-49-002, et al. \n- 145 - \nfrom the December Order, without sufficient explanation, by replacing the term “Point of \nInterconnection” with “Point of Change in Ownership.”687 \n In the instant filing, PJM states that it proposes modifying the definition of                  \nCo-Located Load directed by the Commission in the same manner as proposed in PJM’s \nfirst compliance filing.688  PJM states that changing “Point of Interconnection” to “Point \nof Change in Ownership” is consistent with or superior to the December Order’s directive \nbecause it provides additional clarity to interconnection parties, is easier to administer, \nand reduces litigation potential.689  PJM further explains “[w]hile Point of Change in \nOwnership describes where a developer’s portion of the Interconnection Facilities \nconnect to the Transmission Owner’s portion of the Interconnection Facilities, Point of \nInterconnection is a technical and physical term about ‘where’ those Interconnection \nFacilities connect to the PJM Transmission System.”690  PJM states that the Commission \nhas broad authority to establish the replacement rate under FPA section 206 and that “one \nstakeholder’s conditional protest in Docket No. ER26-1088 offers another alternative for \nthe Commission to consider in reliance on this Commission authority.”691  PJM explains \nthat “Point of Change in Ownership” will reduce litigation because parties “know what \ninterconnection facilities they own and can plan the connection of Co-Located Load to \nsuch facilities accordingly” but that the protest in Docket No. ER26-1088 “does not \nappear inconsistent with recognizing the principle that Co-Located Loads should only \ninterconnect to a Project Developer’s portion of the Interconnection Facilities.”692  PJM \nnotes that under the GIP, the Project Developer’s Interconnection Facilities are the \nInterconnection Facilities between a Generating Facility and the Point of Change in \nOwnership, and include the facilities and equipment and any modification to those \nfacilities and equipment that are necessary to physically and electrically interconnect the \nGenerating Facility.693 \n \n687 PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 (2026). \n688 Compliance Transmittal at 31 (citing PJM, Transmittal, Docket                                  \nNo. ER26-1088-000, at 3 n.14 (filed Jan. 20, 2026)). \n689 Id. at 31-32. \n690 Id. at 32. \n691 Id. at 33. \n692 Id. at 33-34. \n693 Id. at 34-35."},{"page":146,"startToken":55861,"endToken":56319,"text":"Docket No. EL25-49-002, et al. \n- 146 - \nb. \nGeneration Interconnection Procedures, pro forma GIA, \nand Common Service Provisions \n PJM states that it proposes the prescriptive clarifications directed in the December \nOrder.  PJM explains that the proposed Tariff revisions comply by:  (1) adding to the list \nof requirements for a New Service Request that an Interconnection Customer who will \nuse its generating facility to serve Co-Located Load must specify an Eligible Customer \nwho will take transmission service on behalf of the Co-Located Load,694 (2) explaining \nthat if an Interconnection Customer wants to serve Co-Located Load but not identify an \nEligible Customer, then it may take steps to terminate its generating facility’s \ninterconnection and serve the Co-Located Load fully islanded from PJM’s transmission \nsystem,695 (3) explaining that these requirements apply to all Interconnection Customers \nrequesting to interconnect generating facilities to serve Co-Located Load,696 (4) creating \na new schedule in the pro forma GIA in the form of a placeholder to specify operational \nprocedures or data exchange requirements as may be required,697 and (5) revising the             \npro forma GIA to reflect the requirement to specify an Eligible Customer that will take \ntransmission service on behalf of the Co-Located Load.698  \n In addition, PJM states that it complies with the requirement to add a transition \nmechanism for existing customers that wish to add Co-Located Load by including the \ntransition mechanism in (1) the definition of Co-Located Generating Facility in Part I of \nthe Tariff, (2) Part III (NITS), and (3) the definition of Co-Located Generating Facility699 \n \n694 Id. at 28 (citing PJM, Proposed Tariff, pt. VIII, subpt. B, § 403 (4.0.0),             \n§ 403(1)(r)). \n695 Id. at 29 (citing PJM, Proposed Tariff, pt. VIII, subpt. B, § 403 (4.0.0),             \n§ 403 (1)(r); Proposed Tariff, Part III (NITS) (4.0.0)). \n696 Id. (citing PJM, Proposed Tariff, pt. VIII, subpt. B, § 403 (4.0.0), § 403(1)(r); \nProposed Tariff, Part III (NITS) (4.0.0)). \n697 Id. (citing PJM, Proposed Tariff, pt. IX.B (GIA), (0.0.0), Schedule O).  \n698 Id. (citing PJM, Proposed Tariff, pt. IX.B (GIA), (0.0.0), Schedule O). \n699 PJM proposes the following definition of a Co-Located Generating Facility:  \n“an existing or planned Generating Facility that is physically connected to a Co-Located \nLoad.  Any Generation Project Developer with an effective Service Agreement that plans \nto use a Generating Facility to serve Co-Located Load must provide PJM and the \nTransmission Owner with advance written notice to begin the Necessary Studies process \nprovided in Tariff, § VIII.A 401(H)(3)(b).  If such a Generation Project Developer has an \neffective Interconnection Service Agreement pursuant to Tariff, Part VI or a Generation \nInterconnection Agreement pursuant to Tariff, Part VII, such agreement must be"},{"page":147,"startToken":56319,"endToken":56680,"text":"Docket No. EL25-49-002, et al. \n- 147 - \nin Part VIII, Subpart A, section 400 of the Tariff.  PJM asserts that these proposed \nrevisions to the Tariff are “superior to or consistent with the Commission’s directive \nbecause it promotes tariff readability and usability.”700   \nc. \nDefinition of Non-Retail BTMG \n PJM states that it is also seeking to avoid any inadvertent changes to the \nsubstantive rules pertaining to Non-Retail BTMG.701  For this reason, PJM proposes to \nadd clarifying language in Tariff, Part III, section 34.3 providing that “The daily load of a \nNetwork Customer does not include load served by operating Non-Retail Behind The \nMeter Generation.”702  PJM states that this insertion preserves the status quo on this issue \nfor Non-Retail BTMG.   \n3. \nPleadings \na. \nDefinition of Co-Located Load \n Constellation urges the Commission to reject PJM’s proposal to replace the term  \n“Point of Interconnection” in the definition of Co-Located Load with the “Point of \nChange in Ownership.”703  Constellation argues that changing the specific definition of \nCo-Located Load already approved by the Commission in the December Order is outside \nthe scope of compliance.  Constellation asserts that Point of Change in Ownership is not a \ndefined physical point and may lead to delays or discrimination against certain                       \nCo-Location Arrangements.  Constellation states that, alternatively, if the Commission \naccepts PJM’s proposed definition of Co-Located Load, it should (1) direct PJM to revise \nits Tariff to provide that PJM will determine the Point of Change in Ownership if parties \ncannot agree; (2) establish deadlines for parties to mutually agree to, or for PJM to \ndetermine, the location for Point of Change in Ownership; (3) ensure that the location \nselected for the Point of Change in Ownership does not eliminate the load from being   \nCo-Located Load unless the Project Developer and Co-Located Load desire it; and               \n \nsuperseded by a Generation Interconnection Agreement pursuant to Tariff, Part VIII and \nthe pro forma GIA in Part IX, Subpart B.”  PJM, Proposed Tariff, § VII.A 300 \n(Definitions C) (4.0.0); § VIII.A 400, Definitions C (4.0.0). \n700 Compliance Transmittal at 29-30. \n701 Id. at 16. \n702 Id. \n703 Constellation Protest and Comments on Compliance Filing at 2."},{"page":148,"startToken":56680,"endToken":57023,"text":"Docket No. EL25-49-002, et al. \n- 148 - \n(4) not tolerate any discrimination or delay and use its enforcement authority or other \nmechanisms to ensure non-discriminatory open access.704 \n Constellation asserts that recent experience has borne out the concern raised in its \ninitial protest that PJM’s deviation from the Commission’s definition of Co-Located \nLoad will allow transmission owners to effectively block Co-Location Arrangements.705  \nConstellation states that a transmission owner recently notified Constellation that it \nwould not study Constellation’s proposed design for a Co-Location Arrangement unless \nConstellation agreed to transfer ownership of certain facilities to the transmission owner, \nwhich would mean that the load would no longer be on the generator’s side of the Point \nof Change in Ownership.706  Constellation argues that, by conditioning the load’s \ninterconnection on the transmission owner’s ownership of those facilities, the \ntransmission owner would prohibit Constellation’s ability to host Co-Located Load at the \nsite and limit the ability of the Co-Located Load to access the transmission services \nadopted in the December Order.  \n Vistra requests that the Commission reject PJM’s use of “Point of Change in \nOwnership” in its proposed definition of Co-Located Load.707  Vistra argues that PJM’s \nproposed revision to the definition of Co-Located Load creates uncertainty and an \nopportunity for transmission owners to unduly discriminate against certain customers.  \nVistra requests that, if the Commission accepts PJM’s proposed definition, then the \nCommission should direct further compliance to prevent undue discrimination.708  \n Energy Artisans oppose PJM’s definition of Co-Located Load and its use of Point \nof Change in Ownership rather than Point of Interconnection as arbitrary and a pretext for \ncost shifting.709  Energy Artisans allege that the definition “is strategically designed to \nshrink the legal definition of the facility boundary, thereby capturing more load for               \ngrid-service billing and excluding it from the BTMG actual use category.”710  \n \n704 Id. at 3-5, 7-8. \n705 Constellation Supplemental Protest of Compliance Filing at 2. \n706 Id. at 3. \n707 Vistra Protest of Compliance Filing at 17. \n708 Id. at 18-19. \n709 Energy Artisans Protest of Compliance Filing at 2. \n710 Id."},{"page":149,"startToken":57023,"endToken":57395,"text":"Docket No. EL25-49-002, et al. \n- 149 - \nb. \nGeneration Interconnection Procedures, pro forma GIA, \nand Common Service Provisions \n Invenergy argues that PJM proposes to continue operating a bifurcated study \nprocess in which there is no requirement for generator interconnection and transmission \nservice request studies to be conducted in concert, on similar time frames, or using \nsimilar study assumptions.  As a result, Invenergy contends that distinct studies may \nidentify duplicative or unnecessary Network Upgrades.  Invenergy requests that the \nCommission and PJM clarify how the definition of Eligible Customer applies to                   \nco-located generators and co-located loads.711   \n Constellation urges the Commission to direct PJM to revise its proposed definition \nof Co-Located Generating Facility to clarify that the definition only applies to the portion \nof the facility serving and physically connected to the Co-Located Load.712 \nc. \nDefinition of Non-Retail BTMG \n AMP argues that PJM’s proposed revision to the definition of Non-Retail BTMG \ncould be construed as preventing generating units that are merely eligible for application \nof the Non-Retail BTMG rules from participating in Co-Located Load configurations.  \nSpecifically, AMP asserts that the use of the word “qualifies” in the proposed definition \nof Non-Retail BTMG may exclude generation from participating in Co-Located Load \nconfigurations even if the generator is not engaged in netting.  AMP argues that this \napparently unintentional exclusion would restrict Co-Located Load from accessing \nservice from a broad set of PJM generators.  AMP avers that revising the Non-Retail \nBTMG definition is unnecessary and outside the scope of the Commission’s compliance \ndirectives.  AMP urges the Commission to reject the proposed definition of Non-Retail \nBTMG or, alternatively, revise the definition to specify that the exclusion applies to \ngenerators both qualifying as Non-Retail BTMG and being used for netting under the \nTariff.713 \nd. \nTiming with Planned Reliability Backstop Auction \n The Maryland OPC urges the Commission to defer action on PJM’s proposed \nrevisions until PJM announces details regarding its planned reliability backstop auction, \nincluding specifics on how the reliability backstop auction will interact with Co-Location \nArrangements to ensure that new Co-Located Loads pay the costs of any new capacity.  \n \n711 Invenergy Comments on Compliance Filing at 3, 6. \n712 Constellation Protest and Comments on Compliance Filing at 17.  \n713 AMP Limited Protest of Compliance Filing at 3, 5-8."},{"page":150,"startToken":57395,"endToken":57752,"text":"Docket No. EL25-49-002, et al. \n- 150 - \nThe Maryland OPC argues that the proposed Tariff revisions fail to explain how \nincreased capacity costs of allowing existing generators to serve Co-Located Load, as \nopposed to new generators, will be paid by Co-Located Load and not by existing \nratepayers.714   \n4. \nAnswers \n In response to Invenergy, Indicated TOs argue that the Commission should not \nmandate a combined interconnection and transmission study process for Co-Located \nLoads and Co-Located Generators.  Indicated TOs contend this goes beyond the issues \nthe Commission set for hearing, as well as the compliance directed, in the December \nOrder.  Indicated TOs argue that PJM’s proposed coordinated study approach is just and \nreasonable.715 \n Exelon argues that Constellation’s motion for supplemental protest should be \ndenied because it suggests that Constellation’s experience with one transmission owner \nimplies a universal policy.  Exelon states that it is not attempting to prevent large loads, \nco-located or otherwise, and their load serving entities from receiving transmission \nservice in Exelon’s territories.  Exelon also argues that whether a transmission owner \nowns certain equipment does not necessarily inform where the Project Developer’s \ninterconnection facilities connect to the transmission owner’s interconnection facilities.716 \n5. \nDetermination \na. \nDefinition of Co-Located Load \n As in the Commission’s order addressing PJM’s first compliance filing with the \nDecember Order, we reject PJM’s proposed change to the definition of Co-Located \nLoad.717  We note that no party, including PJM, sought rehearing or clarification of this \ndirective, let alone the definition, in response to the December Order.  Even here, PJM \ndoes not allege that the definition of Co-Located Load set out in the December Order is \nunjust and unreasonable.  Rather, PJM proposes to deviate from this definition by \nreplacing the term “Point of Interconnection” with “Point of Change in Ownership” \n \n714 Maryland OPC Protest of Compliance Filing at 10-11. \n715 Indicated TOs April 24 Answer at 4-5. \n716 Exelon Answer at 1, 5-6. \n717 PJM Interconnection, L.L.C., 195 FERC ¶ 61,030; PJM, Proposed Tariff,                         \n§ I.1 Definitions C-D (Co-Located Load) (46.0.0); § VII.A 300, Definitions C                      \n(Co-Located Load) (4.0.0); § VIII.A 400, Definitions C (Co-Located Load) (4.0.0)."},{"page":151,"startToken":57752,"endToken":58188,"text":"Docket No. EL25-49-002, et al. \n- 151 - \nwithout sufficient explanation as to how this proposed deviation complies with the \nCommission’s directive in the December Order.718   \n Accordingly, we direct PJM to file, within 60 days of the date of issuance of this \norder, a compliance filing that revises the Tariff’s definition of Co-Located Load to use \n“Point of Interconnection” instead of “Point of Change in Ownership,” consistent with \nthe Commission’s directive in the December Order.   \nb. \nGeneration Interconnection Procedures, pro forma GIA, \nand Common Service Provisions \n We accept the following of PJM’s proposed revisions to establish rules for \nInterconnection Customers serving Co-Located Load as complying with the December \nOrder:  (1) adding to the list of requirements for a New Service Request that an \nInterconnection Customer who will use its generator to serve Co-Located Load must \nspecify an Eligible Customer who will take transmission service on behalf of the               \nCo-Located Load;719 (2) establishing a new schedule in the pro forma GIA that serves as \na placeholder for specifying any operational procedures or data exchange requirements \nthat PJM deems necessary for Co-Location Arrangements;720 (3) applying these \nrequirements to all Interconnection Customers requesting to interconnect their generators \nto the transmission system and seeking to use those facilities to serve Co-Located \nLoad;721 (4) clarifying that to the extent that an Interconnection Customer wishes to serve \nCo-Located Load using its generator but not identify an Eligible Customer, then the \nInterconnection Customer may take steps to terminate its generator’s interconnection to \nthe PJM transmission system and serve the Co-Located Load fully islanded from PJM’s \n \n718 See, e.g., PJM Interconnection LLC, 119 FERC ¶ 61,179 at P 12 (“The purpose \nof a compliance filing is to make the directed changes and the Commission’s focus in \nreviewing them is whether they comply with the Commission’s previously stated \ndirectives.”) (citing AES Huntington Beach, LLC, 111 FERC ¶ 61,079 at P 60 & n.25). \n719 See December Order, 193 FERC ¶ 61,217 at P 188; PJM, Proposed Tariff,                 \npt. VIII, subpt. B, 403 (4.0.0), § 403(1)(r).   \n720 See December Order, 193 FERC ¶ 61,217 at P 188; PJM, Proposed Tariff,              \nPart IX.B, Schedule O (0.0.0).  PJM explains that it proposes to add a new schedule in the \npro forma GIA in the form of a placeholder for such information as the case may require.  \nCompliance Transmittal at 29.  We also accept conforming changes to Tariff, Part IX.B, \nGIA Appendices and Schedules. \n721 See December Order, 193 FERC ¶ 61,217 at P 189; PJM, Proposed Tariff,                \npt. VIII, subpt.B, 403 (4.0.0), § 403(1)(r)."},{"page":152,"startToken":58188,"endToken":58654,"text":"Docket No. EL25-49-002, et al. \n- 152 - \ntransmission system;722 and (5) revising the pro forma GIA to specify that an \nInterconnection Customer that will use its generator to serve Co-Located Load must \nspecify an Eligible Customer that will take transmission service on behalf of the             \nCo-Located Load.723 \n However, we reject PJM’s proposed revisions to comply with the Commission’s \ndirective in the December Order to require Interconnection Customers with ISAs or GIAs \nexecuted (or requested to be filed unexecuted) prior to the effective date of the revised \ngeneration interconnection procedures and pro forma GIA directed in that order that wish \nto add Co-Located Load or are currently serving Co-Located Load to publicly notify PJM \nof that addition and identify the Eligible Customer that will take transmission service on \nbehalf of that Co-Located Load.724  Consistent with our discussion above in Part V.C.4, \nwe agree with protesters that PJM’s proposed revisions here go beyond the directives in \nthe December Order by requiring Interconnection Customers with existing ISAs or GIAs \nthat are currently serving Co-Located Load or wish to add Co-Located Load (and have \nexecuted Necessary Study Agreements) to initiate a new Necessary Study process and \nenter into a new GIA—which the December Order did not require.725  Therefore, while \nwe appreciate PJM’s intent to promote Tariff readability and usability, we find that \nPJM’s language in the definition of Co-Located Generating Facility does not comply with \nthe December Order, consistent with our findings regarding the same language in Part III \nof the Tariff.726  We further find that PJM has failed to include a general provision in the \nTariff to comply with the Commission’s directive in the December Order to require \nInterconnection Customers with ISAs or GIAs executed (or requested to be filed \nunexecuted) prior to the effective date of the revised generation interconnection \nprocedures and pro forma GIA directed in that order that wish to add Co-Located Load or \nare currently serving Co-Located Load to publicly notify PJM of that addition and \n \n722 See December Order, 193 FERC ¶ 61,217 at P 189; PJM, Proposed Tariff,        \npt. VIII, subpt. B, § 403 (4.0.0), § 403(1)(r).   \n723 See December Order, 193 FERC ¶ 61,217 at P 190; PJM, Proposed Tariff,           \npt. IX (GIA), subpt. B, Schedule O (0.0.0). \n724 See December Order, 193 FERC ¶ 61,217 at P 191; PJM, Part III (NITS) \n(4.0.0); § VII.A 300, Definitions C (Co-Located Generating Facility) (4.0.0); § VIII.A \n400, Definitions C (Co-Located Generating Facility) (4.0.0).  We note that the definition \nof Co-Located Generating Facility in § I.1 Definitions C-D does not include the language \nthat we are rejecting here. \n725 See, e.g., Vistra Protest of Compliance Filing at 4, 14.  \n726 See supra Part V.C.4."},{"page":153,"startToken":58654,"endToken":59086,"text":"Docket No. EL25-49-002, et al. \n- 153 - \nidentify the Eligible Customer that will take transmission service on behalf of that              \nCo-Located Load, separate from the Necessary Study process. \n Therefore, we direct PJM to submit a compliance filing within 60 days of the date \nof issuance of this order to:  (1) revise the definition of Co-Located Generating Facility to \nremove the following requirement:  “If such a Generation Project Developer has an \neffective Interconnection Service Agreement pursuant to Tariff, Part VI or a Generation \nInterconnection Agreement pursuant to Tariff, Part VII, such agreement must be \nsuperseded by a Generation Interconnection Agreement pursuant to Tariff, Part VIII and \nthe pro forma GIA in Part IX, Subpart B,” and (2) add to Part III a requirement that \nInterconnection Customers with ISAs or GIAs executed (or requested to be filed \nunexecuted) prior to the effective date of the revised generation interconnection \nprocedures and pro forma GIA directed in December Order that wish to add Co-Located \nLoad or are currently serving Co-Located Load publicly notify PJM of that addition and \nidentify the Eligible Customer that will take transmission service on behalf of that              \nCo-Located Load. \n We disagree with Constellation that PJM’s proposed definition of Co-Located \nGenerating Facility should only apply to the portion of the facility that is serving                  \nCo-Located Load.  Constellation claims that the definition does not recognize that the \nentire facility may not serve the Co-Located Load, but Constellation has not identified \nany substantive concern with that outcome.  We find the proposed definition is broad \nenough to capture both scenarios.  Further, PJM’s proposed Tariff language recognizes \nthis possibility elsewhere, such as, for example, Part IX, Subpart A Form of Application \nand Studies Agreement, section 2, which leaves a space for the Interconnection Customer \nto list both the Co-Located Load and any requested CIRs. \n With respect to Invenergy’s request that PJM perform generator interconnection \nand transmission service request studies in concert, we note that the December Order did \nnot direct PJM to create such a new study process.  Thus, we find that Invenergy’s \nrequest is beyond the scope of this proceeding. \nc. \nDefinition of Non-Retail BTMG \n We agree with AMP that PJM’s proposed revisions to the definition of Non-Retail \nBTMG may inadvertently prevent generators that could merely qualify as Non-Retail \nBTMG from participating in Co-Location Arrangements, regardless of whether the \ngenerator is being used to net.  As PJM recognizes, the December Order “did not direct \nany changes to Non-Retail BTMG rules.”727  PJM did not provide any justification for its \nproposed changes to the definition of Non-Retail BTMG, nor did the Commission direct \n \n727 Compliance Transmittal at 7."},{"page":154,"startToken":59086,"endToken":59409,"text":"Docket No. EL25-49-002, et al. \n- 154 - \nany changes to PJM’s rules for Non-Retail BTMG in the December Order.728  Therefore, \nwe reject PJM’s proposed revisions to the definition of Non-Retail BTMG and direct \nPJM to file, within 60 days of the date of issuance of this order, a compliance filing to \nrevise its Tariff to remove the proposed changes, consistent with the December Order’s \ndetermination.729 \nd. \nTiming with Planned Reliability Backstop Auction \n As discussed below, we decline Maryland OPC’s request that the Commission \ndefer action.730  We find that Maryland OPC’s concerns about PJM’s capacity market are \nbeyond the scope of this compliance proceeding, which pertains solely to PJM’s \ncompliance with the Commission’s directives in the December Order.   \nE. \nEffective Date \n1. \nPJM Compliance Filing \n PJM requests a placeholder effective date of 12/31/9998 because PJM cannot \nimplement the Tariff changes until the Commission sets the terms and conditions of the \nnew transmission services in the paper hearing.731  PJM states that it will submit a                         \nclean-up filing proposing an effective date after the Commission issues an order on the \npaper hearing.732 \n2. \nEffective Date Pleadings \n Though Vistra says it will address PJM’s proposed June 1, 2029 effective date in \nits paper hearing brief, Vistra argues in its protest of the compliance filing that PJM has \nnot shown that its proposed effective date is just and reasonable.733  Vistra alleges that the \nthree-year forward capacity market schedule cannot justify a delay in the provision of \nnon-capacity-backed transmission service.  Vistra also contends that the forecasts for the \n \n728 December Order, 193 FERC ¶ 61,217 at P 222 (“We clarify we do not direct \nPJM to change its rules for non-retail BTMG.”). \n729 PJM, Proposed Tariff, § I.1 Definitions L-M-N (Non-Retail Behind The Meter \nGeneration) (52.0.0). \n730 See supra Part VI.K.2. \n731 Compliance Transmittal at 35. \n732 Id. at 35-36. \n733 Vistra Protest of Compliance Filing at 7."},{"page":155,"startToken":59409,"endToken":59775,"text":"Docket No. EL25-49-002, et al. \n- 155 - \n2027/2028 and 2028/2029 Base Residual Auctions (BRA) include the new large loads \nlikely to come online in that timeframe, undermining PJM’s position that the capacity \nmarket schedule should delay the provision of firm transmission service.  Vistra also \nargues that PJM has not explained why it will take until 2029 to update its software to \naccommodate the new curtailment logic. \n DCC argues that PJM’s effective date should be earlier than June 1, 2029.734  DCC \nargues that PJM should work with stakeholders to implement workable solutions in a \ntimely manner that ensures the transmission services can meet the immediate need within \nthe PJM region. \n3. \nDetermination \n As discussed below in Part VI.J, we direct PJM to submit, within 60 days of the \ndate of issuance of this order, a further compliance filing providing additional \ninformation on the effective date.  \nVI. \nPaper Hearing \n The Commission directed PJM to modify its Tariff to require that the Eligible \nCustomer taking transmission service on behalf of a Co-Located Load takes one of three \ntransmission services:  (1) NITS or Interim NITS, (2) FCD transmission service, or                 \n(3) NFCD transmission service.735  With respect to the new transmission services that the \nCommission required, the Commission established paper hearing procedures to determine \nthe appropriate rates, terms, and conditions of those transmission services.736  PJM did \nnot file tariff revisions in eTariff, but rather, chose to submit illustrative tariff revisions \nthat mirror the arguments PJM filed in its initial brief as part of that brief.  The illustrative \ntariff is not filed as a rate with the Commission, but we consider it as part of the record in \nresponse to the paper hearing as we establish the replacement rate set forth below.  As \ndiscussed in detail below, as the replacement rate, we direct PJM to submit within                       \n60 days of the date of issuance of this order, a compliance filing revising its Tariff to \ninclude rates, terms, and conditions for the new transmission services consistent with our \nfindings in the below sections.  \n \n734 DCC Comments on Compliance Filing at 7. \n735 December Order, 193 FERC ¶ 61,217 at P 193. \n736 Id. PP 194, 203, 207, 219."},{"page":156,"startToken":59775,"endToken":60085,"text":"Docket No. EL25-49-002, et al. \n- 156 - \nA. \nRates, Terms, and Conditions for Firm and Non-Firm Contract \nDemand Transmission Service \n1. \nDecember Order \n With respect to FCD transmission service and NFCD transmission service, the \nCommission found in the December Order that these transmission services should be \npermanent transmission services available to Eligible Customers taking transmission \nservice on behalf of Co-Located Load.737  The Commission further stated that for the \nEligible Customer taking transmission service on behalf of a Co-Located Load to be \neligible for these new transmission services, the Co-Located Load must be able and \nwilling to prevent or limit its energy withdrawals and must be separately metered from \nthe associated generator.738  The Commission also stated that Eligible Customers taking \ntransmission service on behalf of Co-Located Loads may take a combination of FCD \ntransmission service and NFCD transmission service, but that Eligible Customers taking \ntransmission service on behalf of Co-Located Loads that will not withdraw energy from \nthe transmission system must take NFCD transmission service at 0 MW.739  The \nCommission also found that Eligible Customers taking either transmission service on \nbehalf of Co-Located Loads would be charged for regulation and black start services \nbased on gross demand, rather than the reserved amount of transmission service.740 \n The Commission found that FCD transmission service should have the same \nreservation and curtailment priority as existing firm transmission services at the level of \nthe contract demand and be charged for transmission, ancillary services, and capacity \nbased on the contract demand, with the exception of regulation and black start services.741  \nWith respect to NFCD transmission service, the Commission found that the service \nshould be available during normal operations and curtailed during emergency operations, \nsimilar to existing non-firm transmission service options.742   \n \n737 Id. P 206. \n738 Id.  \n739 Id.  \n740 Id. PP 209, 216. \n741 Id. PP 208-209. \n742 Id. P 215."},{"page":157,"startToken":60085,"endToken":60486,"text":"Docket No. EL25-49-002, et al. \n- 157 - \n2. \nNature of FCD and NFCD Transmission Services \na. \nInitial Briefs \n PJM proposes to define FCD transmission service as the transfer of capacity and \nenergy for an Eligible Customer on behalf of a designated Co-Located Load, up to a \ndefined, pre-determined MW level of transmission service as requested by the Eligible \nCustomer and confirmed by PJM, using capacity and energy procured by PJM.743  PJM \nproposes to define NFCD transmission service as a service offering the transmission of \nenergy for an Eligible Customer on behalf of a designated Co-Located Load, on an                 \nas-available basis, up to a defined, pre-determined MW level of transmission service as \nrequested by the Eligible Customer and confirmed by PJM, using energy procured by \nPJM.744   \n PJM states that it has conceptualized the FCD and NFCD transmission services \nbased on two key principles:  (1) the services are designed to serve loads willing and able \nto control their withdrawals from the transmission system, and (2) the services are \ndesigned to allow PJM to maintain system reliability.745  PJM explains that, to maintain \nreliability, any portion of the gross demand of the Co-Located Load not served by the      \nCo-Located Generator must be covered by FCD transmission service.  PJM also states \nthat, to ensure reliability, PJM’s studies of the transmission service requests for the                      \nCo-Located Load must capture the effects of any unscheduled energy withdrawals and \nvalidate that such events would not jeopardize system reliability.746  PJM then asserts \nthat, if the Co-Located Load’s gross demand is not covered by FCD transmission service, \nthen the Eligible Customer must cover the remaining gross demand by applying for \nNFCD transmission service.  PJM further states that an Eligible Customer taking service \non behalf of a Co-Located Load must request NFCD transmission service equal to the \nMW level of the Co-Located Generating Facility dedicated to serving the Co-Located \nLoad, so that the customer is eligible to obtain NFCD transmission service if the                   \nCo-Located Generating Facility is on outage.747  PJM states that it anticipates that, in \npractice, requests for NFCD transmission service will be at the MW level that the                   \nCo-Located Generating Facility has dedicated to serving the Co-Located Load.  PJM \nstates that the Eligible Customer may then, on any given day, reserve NFCD transmission \n \n743 PJM Initial Brief at 13. \n744 Id. at 30. \n745 Id. at 6. \n746 Id. at 6-7. \n747 Id. at 9, 16."},{"page":158,"startToken":60486,"endToken":60805,"text":"Docket No. EL25-49-002, et al. \n- 158 - \nservice up to the amount specified in the Service Agreement, but only when PJM has \ndetermined there is available transmission capacity.  If there is not sufficient capacity to \ngrant the request for NFCD transmission service, PJM explains the Eligible Customer \nmay apply for FCD transmission service for the necessary amount, or NITS to serve the \nentire Co-Located Load.748  PJM maintains that its approach provides flexibility, \nallowing Eligible Customers to mix and match FCD and NFCD transmission services, so \nlong as the combination of the two services covers the entire gross demand of the                  \nCo-Located Load.749 \n PJM argues that, to prevent FCD and NFCD transmission services from adversely \nimpacting system reliability, it is crucial for the Eligible Customer to show and prove its \nability to limit withdrawals from the system.  PJM maintains that, for FCD transmission \nservice to properly function, it is essential that any NFCD transmission service for the \nsame Co-Located Load has in place necessary control technologies and/or protective \nsystems approved by PJM and that can effectively limit withdrawals from the \ntransmission system that serve the Co-Located Load.750  PJM proposes to require Eligible \nCustomers taking NFCD transmission service to work with PJM and the affected \nTransmission Owners to establish necessary control technologies and protection systems \nfor each Service Agreement to ensure reliability.751 \n PJM explains that FCD transmission service will have priority over NFCD \ntransmission service and equal priority, at the level of the contract demand, with other \nfirm transmission services, including NITS.  PJM proposes that NFCD transmission \nservice be curtailed before FCD transmission service and NITS, as discussed further \nbelow, and proposes to curtail NFCD transmission service prior to dispatching Pre-\nEmergency Load Response Program resources or in response to a transfer capability \nshortage.752   \n \n748 Id. at 32-33. \n749 Id. at 11. \n750 Id. at 15, 31. \n751 Id. at 34-35. \n752 Id. at 15, 34."},{"page":159,"startToken":60805,"endToken":61205,"text":"Docket No. EL25-49-002, et al. \n- 159 - \nb. \nResponse Briefs \n Indicated TOs support PJM’s proposal to require Eligible Customers taking \nservice on behalf of Co-Located Load to take a combination of FCD and NFCD \ntransmission services equivalent to the entire gross demand of the Co-Located Load.753   \n However, a number of parties protest PJM’s proposed requirement that NFCD \ntransmission service be available only when the Co-Located Generating Facility is on an \noutage.754  Parties argue that the December Order does not impose such a limit on this \ntransmission service and that PJM provides no justification for the change.755  AEU/SEIA \ncontend that the December Order required that NFCD transmission service be available \n“as needed during normal, non-emergency system operating conditions,” and that, while \nit cited the use of NFCD transmission service during an outage as one potential use case, \nthe December Order did not impose the limitation described in PJM’s proposed Tariff \nrevisions.756  AEU/SEIA claim that the practical consequences of this limitation are \nsignificant, particularly for Co-Located Loads served by resources with variable or \nintermittent output profiles, which may require supplemental grid withdrawals during any \nperiod in which the Co-Located Generator’s output is constrained, reduced, or otherwise \ninsufficient to meet the full gross demand of the Co-Located Load.  AEU/SEIA argue \nthat this gap in the availability of NFCD transmission service will force many \ntransmission customers to take NITS.   \n AEU/SEIA contend that PJM attempts to justify this restriction on operational and \nplanning complexity grounds, but argues that the Commission considered these \nobjections before the December Order and nonetheless required PJM to provide NFCD \ntransmission service.757  AEU/SEIA also contend that this restriction cannot be justified \non resource adequacy or reliability grounds, because NFCD transmission service is \n \n753 Indicated TOs Response Brief at 4; Industrials/Amtrak Response Brief at 24. \n754 Joint Co-Location Developers Response Brief at 6-13; AEU/SEIA Response \nBrief at 5; Vistra Response Brief at 25; DCC Response Brief at 4; Constellation Response \nBrief at 10. \n755 Vistra Response Brief at 26; AEU/SEIA Response Brief at 5-6; Joint                     \nCo-Location Developers Response Brief at 7; DCC Response Brief at 5; Constellation \nResponse Brief at 10. \n756 AEU/SEIA Response Brief at 6-8 (citing December Order, 193 FERC ¶ 61,217 \nat PP 214-215); Joint Co-Location Developers Response Brief at 6-7. \n757 AEU/SEIA Response Brief at 8-10 (citing PJM March 24, 2025 Response                  \nat 13-15)."},{"page":160,"startToken":61205,"endToken":61541,"text":"Docket No. EL25-49-002, et al. \n- 160 - \ndesigned to be curtailed before firm transmission services and is available only when \ntransmission capacity exists.  AEU/SEIA therefore request that the Commission direct \nPJM to revise and file Tariff revisions that remove the outage-only limitation and allow \nfor the use of NFCD transmission service on an as-available basis during normal,                  \nnon-emergency system operating conditions and subject to available transmission \ncapacity and appropriate curtailment priority.  \n Joint Co-Location Developers argue that PJM’s proposal undermines economic \nefficiency, restricts competition, may threaten reliability for other customers, and is \nunclear as applied to partial outages.758  Joint Co-Location Developers maintain that \nPJM’s proposal is inconsistent with its other transmission service offerings, such as \nPTPS, which is not designed based on whether generation is on an outage.  Joint                    \nCo-Location Developers add that PJM’s Interim NITS proposal shows PJM’s ability to \noffer non-firm service during normal conditions without the need to request a reservation.  \n DCC argues that PJM’s proposal effectively confines NFCD transmission service \nto a narrow, outage-only function and prohibits its use to address foreseeable and \nmanageable transmission constraints.  DCC argues that PJM has not demonstrated why \nNFCD transmission service that is (a) requested in advance, (b) subject to PJM approval, \n(c) fully curtailable, and (d) supported by required protection and control mechanisms, \nmay appropriately be used to address generator outages but may not be used to address \ntemporary transmission constraints.759   \n Constellation also criticizes PJM’s view that this proposal is needed to avoid \noveruse and responds that the Commission indicated that penalty charges should solve \nthat concern.760 \n Constellation also protests PJM’s proposal to require FCD transmission service for \nany portion of the Co-Located Load not served by the Co-Located Generating Facility.  \nConstellation argues that the Commission established no such requirement, nor did the \nCommission require that Eligible Customers take FCD transmission service along with \nNFCD transmission service.761   \n \n758 Joint Co-Location Developers Response Brief at 8-11. \n759 DCC Response Brief at 5.  \n760 Constellation Response Brief at 11-12. \n761 Id. at 10, 12."},{"page":161,"startToken":61541,"endToken":61961,"text":"Docket No. EL25-49-002, et al. \n- 161 - \n DCC argues that PJM’s proposal does not provide a workable pathway for phased \ndevelopment or load ramping.762  DCC argues that PJM’s proposal requires that gross \nload and generation configurations be specified upfront and treats material changes in \nthose configurations as requiring new applications and studies while prohibiting the \nmixing of NITS and Contract Demand transmission services for the same load.  DCC \nargues that, while PJM has acknowledged limited flexibility in certain circumstances, it \ndoes not provide a clear or workable pathway for customers to (a) ramp load over time, \n(b) transition between service constructs, or (c) seek to align transmission service with \nphased project development.  DCC argues that the absence of a defined ramping \nframework introduces uncertainty, increases the risk of delay, and may require repeated \nstudy cycles that are not aligned with project timelines.  DCC argues that the \nCommission should require PJM to establish clear rules and processes that enable \nincremental load additions without triggering unnecessary re-study or requiring \ncustomers to fundamentally restructure their service arrangements.763 \n Market Monitor argues that the assumption underlying NFCD transmission \nservice, that load pays for transmission only when it needs transmission, is untenable.764  \nMarket Monitor states that although NFCD transmission service can only be a standby \nservice, the equivalent availability factor of generators in PJM demonstrates that NFCD \ntransmission service would have to be used regularly.  Market Monitor argues that if all \nor a significant part of data center users wanted to use NFCD transmission service, the \nsystem would become unmanageable and the service would not be available consistently, \nmaking it meaningless.  Market Monitor asserts that there can be no such service as \nNFCD transmission service that is fully consistent with maintaining a reliable PJM \ntransmission system, and all transmission customers should pay for full NITS service.  \nc. \nReply Briefs \n PJM argues that its proposal to limit NFCD transmission service to circumstances \nwhere the Co-Located Generator is on outage is just and reasonable, consistent with the \nDecember Order, and otherwise appropriate.  PJM argues that, if customers could take \nunlimited NFCD transmission service, that would be tantamount to offering Interim NITS \npermanently.765  PJM next argues that the Commission stated in the December Order that \nNFCD transmission service would be available “as needed” for customers able to limit \nwithdrawals, which suggests the Commission did not intend for this service to be used on \n \n762 DCC Response Brief at 6.  \n763 Id. at 6-7. \n764 Market Monitor Response Brief at 5-6. \n765 PJM Reply Brief at 6-7."},{"page":162,"startToken":61961,"endToken":62375,"text":"Docket No. EL25-49-002, et al. \n- 162 - \nan everyday basis.766  Moreover, PJM argues, its proposal is appropriate given the \ninherent risks to the transmission system and operational complexities associated with \nproviding this service continuously, given the limited time period the non-firm service \nwill be required.  PJM asserts that the transmission system is not planned and designed to \naccommodate these non-firm services under North American Electric Reliability \nCorporation (NERC) reliability standards.   \n PJM maintains that several aspects of NFCD transmission service are challenging \nfrom a reliability perspective, given the range of requirements of NERC reliability \nstandards.  PJM alleges that the nature of NFCD transmission service dictates that PJM \nwill not include this service in PJM’s long-term transmission planning and the system \nwill not be evaluated for potential Corrective Action Plans, nor will PJM have procured \ncapacity to serve this load.767  PJM also claims that, because NFCD transmission service \nrelies on transmission capacity that is not currently used, PJM is unlikely to be in a \nposition to provide this service during peaks or other times when the system is operating \nunder stressed conditions.  PJM argues that, from a transmission planning perspective, \nNFCD transmission service increases the operational risk of System Operating Limit and \nInterconnection Reliability Operating Limit (SOL/IROL) exceedances by operating the \nsystem with a reduced margin for contingency to accommodate high-volume loads.768  \nPJM contends that this operation increases the risk of an emergency occurring if \nunexpected conditions occur.  PJM argues that providing NFCD transmission service will \nalmost inevitably require significant adjustments to PJM’s Operating Plan to mitigate \nexceedances of SOLs/IROLs each time service is provided due to the nature of the \nservice.  PJM maintains that, by definition, NFCD transmission service involves a \ncustomer drawing large quantities of power over transmission facilities that were not \ndesigned to serve that load and thus will almost certainly necessitate flowing power over \nvarious facilities near system limits.769 \n Indicated TOs support PJM’s proposals to restrict the use of NFCD transmission \nservice to periods when on-site generation is on outage and claim that the Commission \ndid not intend for this service to be a substitute for FCD transmission service or NITS for \nthe portion of on-site load that will not be served by on-site generation.  Indicated TOs \nargue that there is no compelling reason for NFCD transmission service to be available \n \n766 Id. at 7 (quoting December Order, 193 FERC ¶ 61,217 at P 215). \n767 Id. at 9-10. \n768 Id. at 11-12. \n769 Id. at 12-13."},{"page":163,"startToken":62375,"endToken":62744,"text":"Docket No. EL25-49-002, et al. \n- 163 - \nduring non-outage conditions.770  Indicated TOs claim that limiting the use of NFCD \ntransmission service is necessary to ensure the reliable operation of the PJM transmission \nsystem, particularly because of the increasing use of special protection schemes, remedial \naction schemes, and other control technologies and protective systems.  Indicated TOs \nrecommend that PJM clarify in the Tariff that an “outage” for these purposes is limited to \nperiods where a generator is offline due to a breakdown or maintenance issues and does \nnot cover other instances when a generator is not operating.771   \n Joint Co-Location Developers urge the Commission to reject PJM’s attempt to \nlimit the availability of NFCD transmission service and require PJM to establish a NFCD \ntransmission service product available during normal system conditions as required by \nthe December Order.772  Joint Co-Location Developers contend that the workable                \nnon-firm transmission service offerings that are broadly available are fully consistent \nwith reliable system operation, as demonstrated in other regions that are rapidly moving \nto implement non-firm transmission service offerings.773  Joint Co-Location Developers \nargue that limiting the scope of NFCD transmission service scheduling to generator \noutages, as PJM proposes, will increase reliance on simple withdrawal-limiting protection \nsystems rather than decrease it because it will increase the frequency with which a \ncustomer will not be authorized to withdraw.774  Joint Co-Location Developers explain \nthat this is because withdrawal-limiting protection systems are only active when the \ncustomer cannot withdraw, i.e., because no transmission service has been scheduled.  \nJoint Co-Location Developers argue that PJM should limit the arming of remedial action \nschemes, or avoid installing them in the first place, and instead maximize use of                    \npre-contingency NFCD transmission service curtailment through scheduling, which is \nsimilar to how Southwest Power Pool, Inc. (SPP) and Electric Reliability Council of \nTexas (ERCOT) envision curtailment under the non-firm transmission services that they \nare developing.775 \n In response to DCC’s concerns about phasing in Co-Located Load, PJM maintains \nthat its proposal provides a workable pathway for phased development or load \n \n770 Indicated TOs Reply Brief at 3-4. \n771 Id. at 5-6. \n772 Joint Co-Location Developers Reply Brief at 10-11. \n773 Id. at 1.  \n774 Id. at 7.  \n775 Id. at 8."},{"page":164,"startToken":62744,"endToken":63149,"text":"Docket No. EL25-49-002, et al. \n- 164 - \nramping.776  PJM argues that the obvious path for Co-Located Load that increases over \ntime is NITS, a transmission service designed to accommodate load growth.  If an \nEligible Customer elects Contract Demand transmission service, any change to the \ncontracted amount would require a new service request.  PJM adds that the Eligible \nCustomer could elect to request Interim NITS or FCD transmission service for their full \nload amount ahead of time and use that capacity as their demand increases up to the \napplied for service level.  PJM explains that the Commission directed PJM to offer FCD \nand NFCD transmission services as an alternative to NITS; thus, it is reasonable for this \nnew service to not accommodate load growth as NITS does. \nd. \nAnswer \n Geronimo Power asserts that PJM’s proposed restrictions on NFCD transmission \nservice are inconsistent with the December Order and should be rejected.777  In response \nto PJM’s and Indicated TOs’ concerns with making this service more broadly available, \nGeronimo Power argues that PJM does not need to expand its transmission system or \notherwise change its operations to accommodate this load; rather, it merely needs to \nallow such load to take transmission service when it is available.778  Geronimo Power \nargues that the effect of PJM’s proposal will be to severely limit co-location opportunities \nin PJM, because large loads will need to either co-locate with a resource that can be \ncalled upon at all times or to take NITS or FCD transmission service that will result in the \nsame inefficient and costly grid buildout that the December Order sought to avoid.779 \ne. \nDetermination \n As discussed below, we find that PJM’s proposal does not comply with the \nCommission’s directives in the December Order and would fundamentally alter the \nnature of the FCD and NFCD transmission services that the Commission directed PJM to \ndevelop.  PJM proposes to require that the Eligible Customer taking transmission service \non behalf of a Co-Located Load must take sufficient transmission service to account for \nthe entire gross demand of the Co-Located Load.780  PJM states that an Eligible Customer \ntaking service on behalf of a Co-Located Load must request NFCD transmission service \nequal to the MW level of the Co-Located Generator dedicated to serving the Co-Located \n \n776 PJM Reply Brief at 37-38. \n777 Geronimo Power May 21 Answer at 4.   \n778 Id. at 6. \n779 Id. at 7. \n780 PJM Initial Brief at 6, 9."},{"page":165,"startToken":63149,"endToken":63615,"text":"Docket No. EL25-49-002, et al. \n- 165 - \nLoad, so that the customer is eligible to obtain NFCD transmission service if the          \nCo-Located Generator is on outage.781  PJM also explains that any portion of the gross \ndemand of the Co-Located Load not served by the Co-Located Generator must be \ncovered by FCD transmission service.782  This proposal would tie the amount of FCD and \nNFCD transmission services that an Eligible Customer can request to the size of the      \nCo-Located Generator, rather than allowing the Eligible Customer to select any amount, \nincluding 0 MW for NFCD transmission service, as the Commission directed.  \nSpecifically, the December Order stated that Eligible Customers on behalf of Co-Located \nLoads would be able to take a combination of FCD and NFCD transmission services, but \nthat “Eligible Customers taking transmission service on behalf of Co-Located Loads that \nwill not withdraw energy from the transmission system must take [NFCD] transmission \nservice at 0 MW.”783  PJM’s proposal would do the opposite.  An Eligible Customer \ntaking transmission service on behalf of a Co-Located Load that wished to be served \nentirely by the Co-Located Generator, and not withdraw any energy from the \ntransmission system, would be required under PJM’s proposal to request NFCD \ntransmission service at a level of contract demand equal to the Co-Located Load’s gross \nload.784  Moreover, contrary to PJM’s proposal, nothing in the December Order would \nrequire an Eligible Customer taking transmission service on behalf of a Co-Located Load \nto take FCD transmission service at a level of contract demand that reflects the amount of \nload not served by the Co-Located Generator (or, for that matter, to take FCD \ntransmission service at all).  In short, the December Order does not link the level of \ncontract demand for either FCD or NFCD transmission service that an Eligible Customer \nmay take on behalf of a Co-Located Load to the size of the Co-Located Generator or the \nsize of the Co-Located Load.   \n Taken together, PJM’s proposed new conditions on FCD and NFCD transmission \nservices mean that if PJM determines as a result of studies that it cannot accommodate a \nrequest for NFCD transmission service, the Eligible Customer will be required to request \nand take a firm transmission service (FCD transmission service or NITS) on behalf of the \nCo-Located Load instead.  In the December Order, the Commission directed PJM to \nimplement FCD and NFCD transmission services in response to a finding that the Tariff \nis unjust and unreasonable because it does not include transmission services that reflect \nEligible Customers taking service on behalf of Co-Located Loads that are willing and \nable to limit their energy withdrawals from the transmission system under certain \n \n781 Id. at 9, 16. \n782 Id. at 6-7. \n783 December Order, 193 FERC ¶ 61,217 at P 206. \n784 PJM Initial Brief at 9."},{"page":166,"startToken":63615,"endToken":64076,"text":"Docket No. EL25-49-002, et al. \n- 166 - \nconditions.785  PJM’s proposal does not address this finding and proposes to create FCD \nand NFCD transmission services that continue to fail to recognize this flexibility.  \nMoreover, requiring an Eligible Customer seeking to take transmission service on behalf \nof a Co-Located Load to take FCD transmission service or NITS instead of NFCD \ntransmission service when it does not seek to take firm transmission service would be \ninconsistent with the Commission’s finding in the December Order that the lack of the \nrequired new transmission services could result in unnecessary, costly, and inefficient \nNetwork Upgrades, increasing Network Upgrade costs.786  While we recognize that PJM \nmay determine that there is insufficient available transmission capacity to fulfill a request \nfor NFCD transmission service,787 in that scenario, the Eligible Customer seeking to take \nthat service on behalf of a Co-Located Load should then be able to decide whether it \nwould prefer to request FCD transmission service or NITS to serve the load – in which \ncase it may be responsible for Network Upgrade costs – or to take 0 MW of NFCD \ntransmission service and thus have no contractual right to withdraw power from the \ntransmission system.   \n PJM’s proposal is also inconsistent with the December Order in that PJM proposes \nto limit the amount of NFCD transmission service that may be reserved by an Eligible \nCustomer to a MW level equivalent to the amount of the Co-Located Generator that is on \noutage.788  The December Order did not require such a restriction and instead \ncontemplated that NFCD transmission service would be available during “normal” \noperations when there is sufficient available transmission capacity,789 providing Eligible \nCustomers seeking to take transmission service on behalf of Co-Located Loads the \n \n785 December Order, 193 FERC ¶ 61,217 at P 193. \n786 See id. P 177 (“[F]or Eligible Customers taking service on behalf of              \nCo-Located Loads that do not reserve transmission or take energy from the transmission \nsystem but which receive only regulation and black start services, or that otherwise are \nwilling and able to limit their energy withdrawals from the transmission system, requiring \nsuch Eligible Customers to take NITS on behalf of these Co-Located Loads may in some \ncircumstances result in costly and inefficient transmission system buildout that may not \nbe necessary if such Eligible Customers are willing and able to take a transmission \nservice that requires fewer Network Upgrades to provide, and therefore may result in \nlower Network Upgrade costs, than would NITS.”). \n787 See id. P 215 (stating that reservations for NFCD transmission service “would \nbe available only when there is available transmission capacity, similar to existing                \nnon-firm transmission service options in the Tariff”). \n788 PJM Initial Brief at 32. \n789 December Order, 193 FERC ¶ 61,217 at PP 214-215."},{"page":167,"startToken":64076,"endToken":64563,"text":"Docket No. EL25-49-002, et al. \n- 167 - \nflexibility to request to reserve any amount of NFCD transmission service, regardless of \nwhether the Co-Located Generator was on outage.  The Commission’s reference to \nNFCD transmission service and generator outages was an example and not a threshold \nrequirement for an Eligible Customer to use this service.790  Regardless, because the \nCommission contemplated that the service would be available during normal operations \nwhen there is sufficient available transmission capacity, Eligible Customers seeking to \ntake NFCD transmission service on behalf of Co-Located Loads must be permitted to \nrequest such service on an everyday basis.  Further, contrary to the December Order, \nPJM’s proposal to allow Eligible Customers taking transmission service on behalf of              \nCo-Located Loads to take NFCD transmission service only when the Co-Located \nGenerator is on outage fails to reflect Eligible Customers taking transmission service on \nbehalf of Co-Located Loads that are willing and able to limit their energy withdrawals \nfrom the transmission system under certain conditions because it removes the option to \ntake NFCD transmission service instead of FCD transmission service for portions of the \nCo-Located Load that are not served by the Co-Located Generator.   \n PJM argues that these changes to NFCD transmission service are necessary for \nreliability, to ensure all load is studied.  We disagree.  Co-Located Load is, as defined in \nthe December Order, behind the Point of Interconnection of an interconnected generator, \nand PJM would already know the size of the generator and any Co-Located Load from \nthe interconnection process (or Necessary Study), and possibly the transmission service \napplication process.  While the portion of load for which the Eligible Customer does not \nrequest transmission service would not be modeled by PJM in a transmission service \nrequest as withdrawing energy from the transmission system, this outcome is appropriate \nbecause the Eligible Customer is not intending to withdraw energy from the transmission \nsystem.  However, the potential impact of the Co-Located Load on the reliability of the \ntransmission system will still be studied as part of the Necessary Study process for the \ngenerator interconnection modification, or as part of a New Service Request.  PJM \nalready conducts dynamic studies for Co-Located Load, which evaluate all applicable \nNERC, PJM, and transmission owner-specific contingencies and criteria, consistent with \nPJM’s responsibilities to ensure system reliability.791  These studies utilize a composite \nload model that includes power electronics, cooling, and lighting loads, and the impact of \nthe facility during this study is dependent on the physical parameters of the facility and \n \n790 See id. P 214 (“Eligible Customers taking service on behalf of such loads may, \nhowever, still seek to withdraw energy from the transmission system from time to time \nwhen transmission capacity is available and not needed by firm customers.  For example, \nan Eligible Customer could seek a transmission reservation for a Co-Located Load in \nadvance for the duration of an expected outage of the associated generator.”) (emphasis \nadded). \n791 PJM March 24, 2025 Response at 53."},{"page":168,"startToken":64563,"endToken":64996,"text":"Docket No. EL25-49-002, et al. \n- 168 - \nits control behavior, not the level or type of transmission service taken.792  This model is \na complete model of the facility.793  As such, PJM, as it currently does, will know the full \nimpact of factors unrelated to the contract demand of the Co-Located Load, including \nimpacts on stability margins, short circuit limits, power quality and harmonic distortion, \nvoltage flicker, interaction of active power electronic controls with the system (e.g., \nmitigation of oscillatory behavior), impact of STATCOMs or other reactive \ncompensation devices, and cyclical demand ramps in the sub-synchronous frequency \nrange.  PJM provides no explanation why this data already available to them is \ninsufficient to fully study a Co-Located Load absent changes to NFCD transmission \nservice. \n PJM also argues that providing NFCD transmission service will require \nadjustments to PJM’s Operating Plan to mitigate exceedances of SOLs/IROLs each time \nservice is provided due to the nature of the service.  While serving load using NFCD \ntransmission service may reduce operating margins on the transmission system, PJM has \npresented no evidence that changes to PJM’s Operating Plan will be regularly needed.  \nHowever, should PJM find, based on operating experience in implementing the NFCD \ntransmission service, that significant and frequent manual adjustments are necessary, \nPJM may consider filing an FPA section 205 filing to adjust the curtailment priority of \nNFCD transmission service.   \n PJM also argues that, by definition, NFCD transmission service involves a \ncustomer drawing large quantities of power over transmission facilities that were not \ndesigned to serve that load and thus will almost certainly necessitate flowing power over \nvarious facilities near system limits.  While we acknowledge that NFCD transmission \nservice is designed to use available transmission capacity that is not needed by firm \ntransmission customers, we find that PJM’s assertion that providing such service will \nnecessitate flowing power over various transmission facilities near system limits is \nspeculative.  In any case, as the Commission stated in the December Order, \n“[r]eservations under this service would be available only where there is available \ntransmission capacity, similar to existing non-firm transmission service options in the \n \n792 Id.  We note that NERC has recommended use of the Power Electronic \nReconnecting and Ceasing (PERC1) model, which is a different model than the current  \nmodel PJM utilizes.  However, the general principles are the same.  See NERC, Essential \nAction to Industry:  Computational Load Modeling, Studies, Instrumentation, \nCommissioning, Operations, Protection, and Control at 3 (2026), \nhttps://www.nerc.com/globalassets/programs/bpsa/alerts/level-3-computational-load-\nalert.pdf. \n793 See, e.g., PJM, PJM Dynamic Model Development Guidelines for \nInterconnection Analysis § 6, PJM Dynamic Model Development Guidelines."},{"page":169,"startToken":64996,"endToken":65468,"text":"Docket No. EL25-49-002, et al. \n- 169 - \nTariff.”794  And consistent with the Commission’s findings in establishing non-firm \ntransmission service under its pro forma Open Access Transmission Tariff, providing \nnon-firm transmission service increases efficiency by allowing customers to use lumpy \ntransmission investment on an as-available basis and may reduce the costs for firm \ntransmission service customers by allowing NFCD transmission service customers to \noffset the costs of that investment.795  However, we note that if PJM determines that there \nmay be increased operational risks associated with providing NFCD transmission service, \nit may address those risks by increasing the transmission reliability margin that it uses \nwhen studying and determining whether to grant requests for NFCD transmission service.  \n We recognize that the new FCD and NFCD transmission services represent a \nsignificant change in how transmission service has been historically offered in PJM.  We \nalso recognize that significant changes to PJM’s software may be necessary to integrate \nthe FCD and NFCD transmission services, including to potentially automate some \nprocesses that are currently handled manually by operators with respect to curtailing    \nnon-firm transmission services.  However, the Commission directed the new FCD and \nNFCD transmission services as the replacement rate after finding PJM’s existing Tariff \nunjust and unreasonable.  We therefore direct PJM to submit a compliance filing within \n60 days of the issuance of this order proposing Tariff revisions to permit Eligible \nCustomers to elect to take FCD transmission service or NFCD transmission service \nwithout the limitations that PJM proposes (i.e., (1) the requirement that the Eligible \nCustomer taking transmission service on behalf of a Co-Located Load must take \nsufficient transmission service to account for the entire gross demand of the Co-Located \nLoad, (2) the requirement for an Eligible Customer taking transmission service on behalf \nof a Co-Located Load to take FCD transmission service at a level of contract demand that \nreflects the amount of load not served by the Co-Located Generator, (3) the requirement \nthat an Eligible Customer taking service on behalf of a Co-Located Load must request \nNFCD transmission service equal to the MW level of the Co-Located Generating Facility \ndedicated to serving the Co-Located Load if that portion of the Co-Located Load is not \ncovered by FCD transmission service, and (4) the restriction on the use of NFCD \ntransmission service to only those circumstances where the Co-Located Generator is on \noutage).  Consistent with our determination above to extend the three new transmission \nservices set forth in the December Order to Eligible Customers taking service on behalf \nof load with BTMG that are willing and able to limit their energy withdrawals from the \n \n794 December Order, 193 FERC ¶ 61,217 at P 215. \n795 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,272 (finding “non-firm \ntransmission prices should reflect the interruptibility of the service and should promote \nefficient use of the transmission system”)."},{"page":170,"startToken":65468,"endToken":65870,"text":"Docket No. EL25-49-002, et al. \n- 170 - \ntransmission system under certain conditions, we further direct PJM to reflect this change \nin its compliance filing. \n With respect to DCC’s argument that PJM’s proposal does not provide a workable \npathway for phased development or load ramping,796 we disagree.  Because FCD \ntransmission service is based on a reserved amount of contract demand and does not \naccount for load growth in the way that NITS does, Eligible Customers seeking to \nincrease the amount of load for which they are taking transmission service over time \nshould be required to submit new transmission service requests for any increases in \ncontract demand.  As an alternative, they may request a level of contract demand in their \ninitial transmission service request that reflects their planned total load, even though they \nmay not need the full level of contract demand immediately.  To the extent that neither of \nthese options work for a particular Eligible Customer taking transmission service on \nbehalf of a Co-Located Load, that Eligible Customer should consider taking NITS, which \naccommodates load growth over time, as PJM suggests.797   \n DCC also argues that PJM prohibits the mixing of NITS and FCD or NFCD \ntransmission service for the same load.798  However, in the December Order, the \nCommission explicitly stated that NITS cannot be combined with any of the new \ntransmission services.799  As such, we find that DCC’s argument is an untimely request \nfor rehearing of the December Order and dismiss it.800   \n With respect to DCC’s argument that Eligible Customers serving Co-Located \nLoad should be able to transition between transmission services,801 we note that Eligible \nCustomers taking transmission service on behalf of Co-Located Load that wish to \ntransition from one transmission service to another may do so through the same process \n \n796 DCC Response Brief at 6. \n797 PJM Reply Brief at 37-38. \n798 DCC Response Brief at 6. \n799 December Order, 193 FERC ¶ 61,217 at P 195 n.408 (“Eligible Customers \ntaking NITS on behalf of Co-Located Load may not combine NITS with any of the other \ntransmission services discussed herein.”). \n800 See, e.g., ISO New Eng. Inc., 132 FERC ¶ 61,098 at P 12 (“The Commission \nhas held that requests to alter a compliance filing in a manner that differs from the order \nrequiring the compliance filing constitute a collateral attack on the order requiring the \ncompliance filing.”). \n801 DCC Response Brief at 6."},{"page":171,"startToken":65870,"endToken":66257,"text":"Docket No. EL25-49-002, et al. \n- 171 - \nas any other party requesting new transmission service, with the exception of the                  \nanti-toggling procedures discussed below in Part VI.E. \n Finally, with respect to Market Monitor’s argument that NFCD transmission \nservice is untenable, we dismiss this argument as an untimely request for rehearing of the \nDecember Order.  We disagree that NFCD transmission service is untenable if it is not \navailable constantly; to the contrary, NFCD transmission service is designed to be       \nnon-firm and as-available, meaning that it will sometimes be unavailable or curtailed.  It \nis possible that if, for example, a significant number of Eligible Customers taking \ntransmission service on behalf of Co-Located Loads were to switch to NFCD \ntransmission service, it would be frequently curtailed, but that is the nature of non-firm, \nas opposed to firm, transmission service.  Eligible Customers taking transmission service \non behalf of Co-Located Loads that do not wish to be curtailed should consider \nrequesting a firm transmission service instead. \n3. \nStudy Process \na. \nInitial Briefs \n PJM states that it will coordinate with the affected transmission owner to complete \nstudies, obtain relevant data, and identify any necessary enhancements to the \ntransmission system to accommodate the requested level of service.802  PJM also states \nthat, during the study period, it may perform other studies.   \n PJM proposes that it notify the affected transmission owner of an application for \nFCD transmission service to allow for coordination to study the potential impacts of \nproviding this service on the transmission owner’s system.803  PJM states that it will \ndetermine any necessary studies to provide the requested transmission service.  If studies \nare needed, PJM explains, it will provide an application and studies agreement to the \nEligible Customer in which the Eligible Customer will agree to reimburse PJM for study \ncosts.  PJM also states that it will consider the results of any transmission owner studies. \n PJM proposes that, upon receiving a service request, it will coordinate with the \naffected transmission owner to complete necessary studies to determine whether, and at \nwhat level, NFCD transmission service can be reliably provided.804  PJM proposes that it \nand the affected transmission owner will determine whether additional studies are \nrequired to assess the NFCD transmission service request, and if so, which studies are \n \n802 PJM Initial Brief at 17-18. \n803 Id. at 24. \n804 Id. at 32-33."},{"page":172,"startToken":66257,"endToken":66672,"text":"Docket No. EL25-49-002, et al. \n- 172 - \nappropriate.  PJM proposes that it will provide a written explanation if it determines that \nnone or only a portion of the requested service can be reliably provided.   \nb. \nResponse Briefs  \n Indicated TOs support PJM’s proposed study processes for FCD transmission \nservice and state that it appropriately recognizes the role of transmission owners in \nevaluating load interconnection requests.805  Indicated TOs argue, however, that the \nTariff should specify that load integration studies should be completed first and inform \nthe determination of whether additional studies are necessary for purposes of an Eligible \nCustomer’s request for transmission service on behalf of a Co-Located Load and the \ninterconnection of any on-site generation.  Indicated TOs contend that this requirement \nwould maximize the speed and efficiency of the overall process and avoid potential \nduplication of effort and expense as between PJM and the PJM transmission owners.  \n Indicated TOs state that PJM appears to contemplate that an Eligible Customer’s \ninitial application for NFCD transmission service would serve as a “holding” request and \nthat the actual reservation and use of the service would require the Eligible Customer to \nmake a request and PJM to determine whether or not the requested amount of service is \navailable.806  Indicated TOs further state that the available amount of NFCD transmission \nservice presumably would serve as the basis for determining the relevant charge to the \nEligible Customer.  Indicated TOs request that PJM confirm these understandings and \nadd appropriate Tariff language.  Indicated TOs also request that PJM clarify whether the \nstudy process set forth in section 710.3 of the illustrative tariff provisions is intended to \ncover only the initial service study or also subsequent determinations as to specific \nreservation requests.  Generally, Indicated TOs argue that more detail should be provided \nas to the process for evaluating and granting requests for NFCD transmission service, \nincluding the timelines associated with such requests, particularly with respect to forced \nrather than planned outages.807  Indicated TOs also contend that PJM should specify in \nTariff language that NFCD transmission service will be available for periods from one \nmonth to one hour in duration. \n Several parties argue that PJM’s proposed study process is unjust and \nunreasonable.808  Constellation argues that PJM fails to sufficiently describe its proposed \nstudy procedures for the three new services.  Vistra similarly argues that PJM’s study \n \n805 Indicated TOs Response Brief at 5-7. \n806 Id. at 4. \n807 Id. at 4-5. \n808 Vistra Response Brief at 31, 33-35; Constellation Response Brief at 14-15."},{"page":173,"startToken":66672,"endToken":67116,"text":"Docket No. EL25-49-002, et al. \n- 173 - \nprocess provides too much discretion to PJM and transmission owners to determine \nwhether studies are required, which studies to conduct, the timeline for doing so, and how \nto prioritize different requests.  First, Vistra asserts that PJM does not propose a \nmechanism to assign customers a queue position based on the submission of a complete \napplication.  Vistra also charges that PJM reserves to itself full discretion to determine \nwhether studies must be conducted and what analyses those studies will involve, and \nalleges that the proposed tariff does not appear to limit the results of PJM’s analysis of \ntransmission service requests to the results of duly conducted studies because it states that \nPJM will “consider” the results of the study procedures.809  Vistra and Constellation also \nargue that PJM provides no timelines or deadlines for processing transmission service \nrequests.  Vistra also argues that PJM provides itself total discretion to set study fees with \nno parameters for setting those fees.  Vistra and Constellation express concern that the \ndiscretion in PJM’s proposal creates a risk of undue discrimination.  Vistra and \nConstellation argue that PJM’s proposal violates the Commission’s rule of reason policy \nbecause the information missing from the tariff proposal significantly affects rates, is \nreadily susceptible of specification, and is not so readily understood as to render \nrecitation superfluous.810  Vistra also contends that PJM’s proposal is unclear on what it \nmeans to ensure that non-firm transmission service can be provided “reliably,” and \nrequests that PJM articulate the standard.811 \nc. \nReply Briefs \n PJM maintains that its illustrative tariff contains an appropriate amount of detail \non the study process and states that it will work with stakeholders to develop \nimplementation details to be set forth in the PJM manuals.812  PJM avers that the \nillustrative tariff provides more than enough detail to satisfy the Commission’s rule of \nreason policy.  PJM alleges that its proposal builds on its existing processes for studying \nrequests for new transmission service requests.  PJM contends that its evaluation of firm \ntransmission service requests will require and follow similar study procedures to what is \nnow required for NITS.  For non-firm transmission service requests, PJM asserts that the \nstudy approach could differ widely for each request and will depend on a number of \nfactors.   \n PJM explains that, currently, the transmission owners study in the first instance all \nrequests to connect new load to the transmission system.  PJM states that, for each zone, \n \n809 Vistra Response Brief at 33-34 (citing PJM, Initial Brief, attach. A § 702.3). \n810 Id. at 36-37, 53; Constellation Response Brief at 15-18. \n811 Vistra Response Brief at 39. \n812 PJM Reply Brief at 22-23, 26, 32."},{"page":174,"startToken":67116,"endToken":67529,"text":"Docket No. EL25-49-002, et al. \n- 174 - \nthe transmission owner studies the integration of the requested load and identifies \nupgrades.  PJM says that it then performs a “do no harm” analysis of how those \ntransmission owner-identified upgrades would affect the regional transmission system.  \nPJM notes that NITS can then be provided consistent with the in-service date of the \nidentified upgrades.813  PJM contends that the allocation of responsibilities between the \ntransmission owners and PJM in the current study process follows the division of rights \nrecently affirmed by the Commission and courts, i.e., transmission owners’ reservation of \nrights over local transmission planning and PJM’s responsibility for the regional \ntransmission system.814  PJM claims that it maintains this division of rights in the \nillustrative tariff provisions. \n PJM also rejects protesters’ arguments that its proposal affords PJM and the \ntransmission owners inappropriate discretion.  PJM argues that it seeks no more \ndiscretion than it currently has under its existing study processes.  PJM argues that its \nevaluation of the transmission system to determine whether it can reliably provide the \nrequested transmission service requires an exercise of engineering judgment, which \ninherently entails a reasonable exercise of discretion.815   \n PJM argues that reliability reviews inherently require PJM to make judgment calls \nas the transmission provider and a NERC-designated Reliability Coordinator, and the \nflexibility to determine whether new transmission facilities are reasonably likely to be       \nin-service fits squarely within PJM’s expertise.  PJM asserts that protesters’ concerns \nabout the level of detail generally concern the transmission owner’s load integration \nstudies, which PJM argues does not inherently implicate the Commission’s jurisdiction \nunder the FPA.816  In response to concerns about study timelines, PJM contends that its \nevaluation of any transmission service request is dependent on the load integration \nstudies performed by the applicable transmission owner.817  PJM asserts that it does not \n \n813 Id. at 24. \n814 Id. at 24 & n.68 (citing PJM Interconnection, L.L.C., 172 FERC ¶ 61,136, \norder on reh’g, 173 FERC ¶ 61,225, at P 19 (2020), aff’d sub nom. Am. Mun. Power, Inc. \nv. FERC, 86 F.4th 922 (D.C. Cir. 2023); PJM Interconnection, L.L.C., 173 FERC                     \n¶ 61,242 (2020), order on reh’g, 176 FERC ¶ 61,053 (2021), aff’d sub nom. Am. Mun. \nPower, Inc., 86 F.4th 922; Monongahela Power Co., 164 FERC ¶ 61,217, at P 14 (2018); \nAppalachian Power Co., 170 FERC ¶ 61,196, at P 59 (2020)). \n815 Id. at 25-26.  \n816 Id. at 34. \n817 Id. at 28."},{"page":175,"startToken":67529,"endToken":67909,"text":"Docket No. EL25-49-002, et al. \n- 175 - \nhave authority to dictate timelines to transmission owners to complete their studies, given \nthat load integration studies are a matter of local transmission planning.   \n PJM also alleges that concerns that PJM will reject transmission service requests \nwithout basis are unfounded.818  PJM maintains that it will generally grant requests for \nNITS and FCD transmission service, and PJM will grant Interim NITS requests \nconsistent with the results of any study/studies.  As to NFCD transmission service, PJM \nexplains that, if it denies a request in whole or in part, PJM will provide a written \nexplanation to the customer of PJM’s reasoning for the denial, which could form the \nbasis for any complaint to the Commission. \n Moreover, PJM argues that the illustrative tariff puts all parties on sufficient notice \nas to how PJM will determine whether it can provide the requested transmission service \nand the study procedures to arrive at that determination.819  PJM asserts that the \nillustrative tariff provides the standard to which PJM will evaluate the requests—whether \nthe requested level of service can be provided reliably.   \n Indicated TOs concede that more detail regarding the study processes for the new \ntransmission services could be helpful, but they argue that commenters’ concerns as to \nthe potential for delays and undue discrimination are overstated.  Indicated TOs contend \nthat it is appropriate and consistent with the Commission’s rule of reason to reference the \nneed to incorporate each transmission owner’s technical requirements in the Tariff while \nomitting the details.  Indicated TOs do not oppose making explicit in the Tariff that the \nstudies referred to are those that the transmission owners will conduct to integrate large \nload facilities.  Indicated TOs reject claims that they will use their role in the study \nprocess to delay or deny Co-Location Arrangements or discriminate against Co-Located \nLoad.820 \n Constellation requests that the Commission deter delays and potential disputes by \n(1) establishing deadlines for studies and other transmission owner approvals or \nconsultation requirements, and (2) require PJM’s and transmission owners’ standards, \nrequirements, guidance, and practices on Co-Location Arrangements to be on file with \nthe Commission on a standalone basis or reflected in the Tariff.821 \n \n818 Id.  \n819 Id. at 30. \n820 Indicated TOs Reply Brief at 9-11. \n821 Constellation Reply Brief at 11-12."},{"page":176,"startToken":67909,"endToken":68234,"text":"Docket No. EL25-49-002, et al. \n- 176 - \n PJM argues that Vistra oversimplifies the provision of non-firm transmission \nservice.822  PJM states that it is not the case that the transmission system has significantly \nunderutilized capacity to provide the envisioned services.  PJM alleges that it needs to \ncarefully identify and manage operational risk instead of spontaneously managing                     \nnon-firm load under an increasingly stressed system.  Constellation also argues that PJM \nshould clarify how it will determine the future and real-time availability of NFCD \ntransmission service, which should be based on when transmission capacity is available \nand not needed by firm customers, consistent with the December Order.823 \nd. \nAnswers \n Constellation argues that the Commission has jurisdiction to regulate load \nintegration studies in connection with jurisdictional transmission service.824  \nConstellation contends that the Commission should exercise jurisdiction over the load \nintegration studies needed to provide jurisdictional transmission service and direct that \nthese studies be on file, including study deadlines and violations to be studied.825 \n Indicated TOs argue that transmission owner processes for studying the integration \nof new retail loads do not implicate the Commission’s jurisdiction, even though such \nstudies will be used as an input in PJM’s process for studying applications for the new \ntransmission services.826  Indicated TOs point out that, even as to studies for \nCommission-jurisdictional services, the Commission does not require transmission \nproviders to file studies.827  Indicated TOs maintain that, if an Eligible Customer disputes \nthe outcome of PJM’s study process for the new transmission services, the customer can \nseek redress through the Commission.   \ne. \nDetermination \n We find that PJM’s proposal regarding study procedures for FCD and NFCD \ntransmission services is not sufficiently detailed to be just and reasonable, and we direct \n \n822 PJM Reply Brief at 35-36. \n823 Constellation Reply Brief at 18 (citing December Order, 193 FERC ¶ 61,217                \nat P 214). \n824 Id. at 6. \n825 Id. at 7. \n826 Indicated TOs May 28 Answer at 8. \n827 Id. at 9."},{"page":177,"startToken":68234,"endToken":68683,"text":"Docket No. EL25-49-002, et al. \n- 177 - \nPJM to file, as the replacement rate, more detailed study procedures that mirror the \nexisting study procedures for transmission service on compliance.828  First, with respect \nto FCD transmission service, we agree with parties on briefing that PJM’s proposal is \nvague and unclear.  We direct PJM to file Tariff revisions on compliance to study \nrequests for FCD transmission service using the same process PJM uses for new service \nrequests for NITS, i.e., the cluster study process.829  This requirement is just and \nreasonable because it will treat new firm transmission service requests similarly.   \n PJM contends that its proposal “has built on its existing processes for studying \nrequests for new transmission services . . . with additional processes necessary to study \nthe novel aspects of Interim NITS and [FCD and NFCD] Transmission Services.”830  \nPJM also states that “[e]valuation of firm service requests will require and follow similar \nstudy procedures to what is now required for NITS.”831  However, PJM’s proposal is \nlacking in detail.  It is not clear whether PJM proposes to study requests for FCD \ntransmission service serially or through its existing cluster study process.832   \n Regardless, we find that it is just and reasonable to study requests for FCD \ntransmission service through PJM’s existing cluster study process, and we direct PJM to \nfile Tariff revisions on compliance consistent with this directive.  We find a serial study \nprocess for new FCD transmission service requests, rather than a cluster study as for new \nNITS requests, would provide disparate treatment to FCD transmission service requests.  \nPJM also does not address a timeline for its study process, meaning FCD transmission \nservice requests could be studied more quickly or more slowly than requests in the new \nservices queue.  PJM does not provide a reason for this difference or any explanation as \nto why such requests should not be studied in the normal cluster process for new service \nrequests.  Further, studying such requests as part of the established cluster study process \n \n828 We discuss PJM’s proposed study procedures for Interim NITS below in                  \nPart VI.H. \n829 PJM, Intra-PJM Tariffs, OATT, § III.32.3 Initial Study Procedures (3.0.0) (“A \nrequest for service for which a Phase I System Impact Study is required is subject to the \nSystem Impact Study Procedures, as set forth in Tariff, Part VII or Tariff, Part VIII, as \napplicable.”). \n830 PJM Reply Brief at 23. \n831 Id. at 26. \n832 See PJM, Initial Brief, attach. A, § 712.1 (“After receiving the Application for \nFirm Contract Demand Transmission Service, the Transmission Provider shall determine, \nin accordance with the PJM Manuals, any necessary studies for reliably providing the \nrequested Firm Contract Demand Transmission Service.”)."},{"page":178,"startToken":68683,"endToken":69158,"text":"Docket No. EL25-49-002, et al. \n- 178 - \nwould address many of the concerns in the record because it would ensure Eligible \nCustomers have more detail, transparency, and certainty regarding the study process, \nwhich is the primary concern of the protesters.833  Thus, we direct PJM to submit a \ncompliance filing within 60 days of the date of issuance of this order to revise its Tariff to \nprovide that it will study FCD transmission service requests using its existing process for \nstudying firm transmission service requests.  Consistent with our determination above to \nextend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions, we \nfurther direct PJM to reflect this change in its compliance filing. \n With respect to NFCD transmission service, we agree with parties arguing that \nPJM’s proposal lacks specificity.  PJM argues that “the study approach could differ \nwidely for each request, given the different nature of the risks involved, as the system \nwould be operated on an as-conditions-permit basis.”834  The lack of detail creates a level \nof discretion that is not just and reasonable; while some amount of discretion is likely \nnecessary to ensure PJM is able to perform any additional studies necessary to maintain \nreliability, Eligible Customers must have some understanding of the study process PJM \nwill use to evaluate transmission service requests.  Therefore, we direct PJM to submit a \ncompliance filing within 60 days of the date of issuance of this order that revises its \nTariff to include study procedures for NFCD transmission service requests.  We note that \nthe Tariff includes detailed procedures for the study of Non-Firm PTPS, which serve as a \nuseful reference.  In particular, the Tariff provides that, following receipt of a tendered \nschedule, PJM will make a determination on a non-discriminatory basis of available \ntransfer capability for PTPS requests, based on a specific methodology detailed in Tariff, \nAttachment C.835  No party has shown why a similar process should not apply for NFCD \ntransmission service, and PJM has not demonstrated that having so little detail in the \nTariff regarding the process for studying requests for NFCD transmission service is just \nand reasonable.  PJM’s compliance filing must also include details about the term length \nof NFCD transmission service, including the minimum term.  Consistent with our \ndetermination above to extend the three new transmission services set forth in the \nDecember Order to Eligible Customers taking service on behalf of load with BTMG that \n \n833 See PJM, Intra-PJM Tariffs, pt. VIII, § 404 (1.0.0) (providing overview of \nsystem impact studies, including scope of studies). \n834 PJM Reply Brief at 26. \n835 See PJM, Intra-PJM Tariffs, OATT, §§ II.15.2, II.18.4; id. attach. C \n(Methodology to Assess Available Transfer Capability)."},{"page":179,"startToken":69158,"endToken":69592,"text":"Docket No. EL25-49-002, et al. \n- 179 - \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions, we further direct PJM to reflect this change in its compliance filing. \n Indicated TOs request that the Tariff specify that transmission owner load \nintegration studies will be completed first and thereby inform what additional studies are \nnecessary.  However, it is not clear from the record what these studies entail, as these \nstudies are not defined in either the Tariff or any of PJM’s manuals, or how transmission \nowners will study the load.  For example, the record indicates that Indicated TOs view a \nload integration study for Co-Located Load as potentially analyzing “(i) what, if any, \nupgrades are needed to accommodate the physical gross load amount behind the point of \ninterconnection.”836  To the extent PJM intends to permit transmission owners to study \nCo-Located Load as if it were native load with NITS, that would not be just and \nreasonable for FCD and NFCD transmission services.  We therefore direct PJM to \nspecify in a compliance filing, which it must submit within 60 days of the date of \nissuance of this order, how transmission owners shall participate in PJM’s study process \nfor Eligible Loads for FCD and NFCD transmission services and specify in detail the \nrelated roles and responsibilities of PJM and the transmission owners in such studies.  We \ndecline at this time to adopt Indicated TOs’ requests to incorporate further revisions to \nthe Tariff related to load integration studies.837 \n4. \nRates and Charges \na. \nInitial Briefs \n Indicated TOs propose that the rate for the FCD transmission service be based on \nthe zonal NITS rates and underlying NITS revenue requirements.838  Indicated TOs argue \nthat Eligible Customers taking FCD transmission service on behalf of Co-Located Load \nand Network Customers should be charged the same rate because the level of service \nprovided to both is the same for all relevant purposes.  For example, Indicated TOs argue \nthat both services are firm transmission services for which PJM procures capacity for the \ncustomers.  Indicated TOs argue that it would be unjust and unreasonable and unduly \ndiscriminatory to charge FCD transmission service customers a rate lower than the NITS \nrate as it would subsidize FCD transmission service customers at the expense of Network \nCustomers.  Indicated TOs contend that it is appropriate to use the single peak coincident \ndemand to calculate the FCD transmission service rate because it is an annual service.  \n \n836 Indicated TOs Initial Brief at 25-26 (emphasis added). \n837 Indicated TOs Response Brief at 13, 16, 19. \n838 Indicated TOs Initial Brief at 6, 8-9."},{"page":180,"startToken":69592,"endToken":69980,"text":"Docket No. EL25-49-002, et al. \n- 180 - \n Indicated TOs propose that NFCD transmission service pay a charge for the \nreserved contract demand amount multiplied by a zonal NFCD transmission service rate \ndetermined based on the specific term of service.839  Indicated TOs propose to use the \nsame FCD transmission service rate for purposes of establishing the maximum rate for \nNFCD transmission service.  Indicated TOs argue that it is just and reasonable to use the \nsame maximum rate for FCD and NFCD transmission services, because the Commission \nhas permitted pricing Non-Firm PTPS at the rate used for Firm PTPS and because the \nCommission provides flexibility to arrange and schedule NFCD transmission service.  \nIndicated TOs allege that NFCD transmission service is superior to Non-Firm PTPS \nbecause PJM will re-dispatch generation prior to curtailing NFCD transmission service.  \nIndicated TOs propose to consider on a going-forward basis whether a discount is \nappropriate for NFCD transmission service based on system conditions and use patterns.   \n In addition to these charges, PJM proposes to assess, for FCD transmission \nservice:  (1) administrative service charges, (2) ancillary service charges, (3) black start \nservice charges based on gross demand, (4) regulation charges based on gross demand, \nand (5) any redispatch costs.  PJM contends that these are standard charges associated \nwith use of the transmission system above transmission service rates.840  For NFCD \ntransmission service, PJM also proposes to assess certain charges within its authority:   \n(1) administrative charges, (2) ancillary services charges, (3) any redispatch costs,                    \n(4) regulation charges based on gross demand, and (5) black start service charges based \non gross demand.841   \nb. \nResponse Briefs \n Several parties argue that it is just and reasonable to charge the same rate for FCD \ntransmission service and NITS.842  NOVEC explains that Eligible Customers are \nreceiving a service commensurate with NITS and should therefore pay a cost \ncommensurate with NITS in recognition of the Commission’s cost causation principles.  \nMarket Monitor asserts that if customers have the option to convert from FCD \ntransmission service to NITS in the future, and given the long timelines in transmission \nplanning and the extreme lumpiness of transmission investments, PJM must plan as if all \n \n839 Id. at 10, 11-13. \n840 PJM Initial Brief at 27. \n841 Id. at 36-37. \n842 ODEC Response Brief at 8; NOVEC Response Brief at 6-7; Market Monitor \nResponse Brief at 3-4."},{"page":181,"startToken":69980,"endToken":70382,"text":"Docket No. EL25-49-002, et al. \n- 181 - \nEligible Customers taking the new contract demand transmission services are Network \nCustomers.  \n Some parties also agree that it is just and reasonable to use the FCD transmission \nservice rate as the maximum rate for NFCD transmission service.843  NOVEC argues that \nNFCD transmission service is a network-type service that bears a resemblance to NITS.  \nNOVEC notes that because an Eligible Customer only purchases NFCD transmission \nservice when reserved, transmission costs for an Eligible Customer are lower than firm \nrates.  \n Other parties disagree that the proposed rate for NFCD transmission service is just \nand reasonable.844  Vistra alleges that Indicated TOs fail to justify not offering a \ndiscounted rate for NFCD transmission service when such a discount exists for Non-Firm \nPTPS.  Vistra contends that the benefit of re-dispatching generation prior to curtailment \ndoes not justify charging a substantially higher rate for a service that is otherwise inferior.  \nVistra also argues that Indicated TOs’ proposal is unjust and unreasonable and unduly \ndiscriminatory because it would create cost shifts between classes of transmission \ncustomers, where Eligible Customers taking NFCD transmission service on behalf of    \nCo-Located Load shoulder the cost of firm transmission service, despite taking non-firm \ntransmission service.  \n Joint Co-Location Developers argue that pricing NFCD transmission service at the \nsame rate as FCD transmission service is not consistent with cost causation principles or \nthe Commission’s purpose in establishing the NFCD transmission service to avoid \ninefficient system buildout.  Joint Co-Location Developers maintain that, as compared to \nFCD transmission service, the rate for NFCD transmission service should reflect the \nlesser costs caused by and lesser benefits received by customers taking this service.845  \nJoint Co-Location Developers claim that, in Order No. 888-A, the Commission explained \nthat, while in some circumstances non-firm transmission rates may be set at the firm \ntransmission rate level, the Commission expects that non-firm transmission rates would, \nin most instances, be priced below the price cap.846 \n Geronimo Power states that, combined with PJM’s proposed requirement that an \nEligible Customer take NFCD transmission service for the portion of its load served by a \n \n843 ODEC Response Brief at 8; NOVEC Response Brief at 7. \n844 Vistra Response Brief at 16-17, 23-24; Joint Co-Location Developers Response \nBrief at 20; Geronimo Power Response Brief at 4.  \n845 Joint Co-Location Developers Response Brief at 20-21. \n846 Id. at 22 (citing Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,272)."},{"page":182,"startToken":70382,"endToken":70842,"text":"Docket No. EL25-49-002, et al. \n- 182 - \nCo-Located Generator, the implication of the Indicated Transmission Owners’ proposal \nappears to be that an Eligible Customer taking NFCD transmission service would be \nrequired to pay a transmission charge equivalent to the rate paid by transmission \ncustomers taking firm transmission service.847  Geronimo Power argues that charging \ntransmission customers taking NFCD transmission service the same amount as a \ntransmission customer taking FCD transmission service is unjust and unreasonable and \ninconsistent with cost causation principles because these loads will be required to pay a \nrate equivalent to customers receiving a higher level of service.  Geronimo Power asserts \nthat non-firm transmission service should be, and often is, priced lower than firm \ntransmission service, such as in PJM where Non-Firm PTPS customers receive a discount \nas compared to Firm PTPS customers.  Geronimo Power adds that the proposed rate \nwould undermine the incentive for large load customers to reduce their reliance on the \ngrid and therefore would fail to offer a rate that would encourage the efficient use of the \ntransmission system, contrary to the December Order.  Further, Geronimo Power states \nthat Indicated TOs should not set an unjust and unreasonable rate based on superior \nservices while they wait until they gather more data to determine the extent to which such \nunjust and unreasonable rate should be reduced when charging for an inferior service.   \n ODEC agrees that it is reasonable for PJM to charge FCD and NFCD transmission \nservice customers for applicable PJM administrative charges consistent with PJM’s \ncharges to existing transmission customers.848   \n ODEC urges the Commission to direct further compliance filings in order to \nensure that rates for the new FCD transmission service are just and reasonable by \nrequiring the individual transmission owners to either confirm that their formula or stated \nrates and metrics reporting enable direct crediting by PJM, or provide whatever revisions \nare necessary in order to do so.849  ODEC states that this is important so that ODEC and \nother Network Customers are not subject to paying duplicative charges for the same \nrevenue requirement amount.  ODEC adds that it is also important because Indicated TOs \nstate that load-serving entities will submit metrics to PJM used to calculate transmission, \ncapacity, and energy charges, but such metrics may not be consistent among Indicated \nTOs.  ODEC explains that, while it is a load-serving entity, as a transmission customer \nthe metrics are provided to PJM by the transmission owners for the zones where ODEC \ntakes transmission service. \n Constellation seeks clarification that Indicated TOs’ proposed rate for FCD \ntransmission service is equal to the applicable transmission owners’ NITS rate calculated \n \n847 Geronimo Power Response Brief at 4, 6, 7-9. \n848 ODEC Response Brief at 8; see also NOVEC Response Brief at 8. \n849 ODEC Response Brief at 8-9."},{"page":183,"startToken":70842,"endToken":71242,"text":"Docket No. EL25-49-002, et al. \n- 183 - \nusing that transmission owners’ coincident peak methodology, given that different \ntransmission owners use different methods.850 \n Industrials/Amtrak argue that the Commission must ensure that transmission \nowners’ calculation of individual customer and zonal transmission cost allocation is \ntransparent, whether through an Attachment M-2 filing or another publicly transparent \nand accountable method.851  Industrials/Amtrak also contend that the Commission must \nprovide direction on how the revenue and the billing determinants for FCD and NFCD \ntransmission services and Interim NITS would be incorporated into existing transmission \nformula rates.  Similarly, Geronimo Power states that the Commission should at a \nminimum require the Indicated Transmission Owners to clarify the nature of the rates and \nbilling determinants that they are proposing, including whether they intend to charge the \nNFCD transmission service charge on a MWh basis, which would be inconsistent both \nwith how transmission reservation charges are historically structured and the Tariff.852   \n Industrials/Amtrak argue that neither FCD nor NFCD transmission service provide \na cost-based back-up service for cogeneration QFs and similarly-situated retail \ncustomers.853  Industrials/Amtrak contend that, because it would require payment for \nservice based on the contracted amount, FCD transmission service inherently assumes \nthat forced outages or other reductions in electric output by all QFs will occur \nsimultaneously, or during the system peak, or both, without any factual data to support \nthat assumption.854  Industrials/Amtrak aver that this is not a realistic assumption for \ncogeneration QFs.  Industrials/Amtrak further argue that it would not comport with cost \ncausation principles to require a FCD transmission service reservation for occasional \nback-up power needs, particularly where the history and risk of the individual unit is \nwell-established or has met outside standards.  Industrials/Amtrak further argue that \nNFCD transmission service also falls short because it requires pre-scheduling with and \napproval by PJM, which is inconsistent with back-up power’s use in the event of forced \noutages, and because it is an as-available product that is subject to interruption.855  \nIndustrials/Amtrak argue that, if the existing netting construct is no longer available, then \na firm transmission service must be available for QFs to meet the requirements of \n \n850 Constellation Response Brief at 31. \n851 Industrials/Amtrak Response Brief at 25-26. \n852 Geronimo Power Response Brief at 5 n.13. \n853 Industrials/Amtrak Response Brief at 16-19. \n854 Id. at 17 (citing Dauphinais Aff. ¶ 44). \n855 Id. at 18."},{"page":184,"startToken":71242,"endToken":71619,"text":"Docket No. EL25-49-002, et al. \n- 184 - \nPURPA based on actual use.  Industrials/Amtrak contend that there must be a \ntransmission service that applies cost causation standards to occasional, unplanned use of \nthe transmission system.   \n Industrials/Amtrak argue that cost causation principles dictate that the \nCommission should authorize cost-based back-up service for all transmission customers, \nnot only QFs.856  Industrials/Amtrak explain that there are a number of facilities that \noperate on similar principles to QFs but do not maintain QF status for a variety of \nreasons.  Industrials/Amtrak argue that these facilities, too, must occasionally draw from \nthe grid, including for occasional unscheduled outages.  Industrials/Amtrak argue that it \ncannot be just and reasonable or comport with cost causation principles to require \nfacilities requiring only occasional back-up service to pay rates that are the same as FCD \ntransmission service or gross-based NITS.  Industrials/Amtrak argue that transmission \ncustomers should be charged based on actual use on an hourly basis and should not be \ncharged a standby fee.    \n Industrials/Amtrak explain that QFs are entitled to supplementary power, back-up \npower, maintenance power, and interruptible power pursuant to Commission \nregulations857 and that the rates for back-up power “[s]hall not be based upon an \nassumption (unless supported by factual data) that forced outages or other reductions in \nelectric output by all [QFs] on an electric utility’s system will occur simultaneously, or \nduring the system peak, or both.”858  Industrials/Amtrak argue the NITS BTMG netting \nconstruct meets the requirements of PURPA’s enacting regulations.  \nc. \nReply Briefs \n In response to Constellation’s request for clarification, Indicated TOs clarify that \nthe zonal FCD transmission service rate will be calculated using that transmission \nowner’s specific methodology applicable to Network Customers.859 \n NOVEC explains that because under PJM’s proposal a transmission customer \nwould only take and pay for NFCD transmission service when the generator was \nexperiencing an outage, the same rate does not equate to the same cost to the customer.860  \n \n856 Id. at 20-22, 24. \n857 Industrials/Amtrak Response Brief at 14-16 (citing 18 C.F.R. § 292.305(b)). \n858 Id. at 15 (citing 18 C.F.R. § 292.305(c)(1)). \n859 Indicated TOs Reply Brief at 18 (citing Constellation Response Brief at 31). \n860 NOVEC Reply Brief at 10-13."},{"page":185,"startToken":71619,"endToken":72057,"text":"Docket No. EL25-49-002, et al. \n- 185 - \nNOVEC argues that NFCD transmission service does not impose fewer costs on the \ntransmission system than NITS, just “imposes costs differently” and contends that the \nCommission needs to be cautious to avoid providing “co-located generators a subsidized \nlow cost option to use the system whenever they need backup.”861  NOVEC argues that \nCo-Located Load in areas where PJM can accommodate a large amount of NFCD \ntransmission service could end up with the best of both worlds, where they are very rarely \ncurtailed but pay a subsidized rate for transmission service, with the option to switch \nfrom FCD transmission service or NITS if PJM can no longer accommodate the required \nlevel of NFCD transmission service.  \n In response to arguments from Joint Co-Location Developers and Geronimo \nPower about whether it is appropriate to establish NFCD transmission service rates based \non FCD transmission service rates, Indicated TOs argue that transmission owners need to \ngather data on how NFCD transmission service customers are using the service and the \neffect of that utilization on the transmission system.862  Indicated TOs argue that it is not \nclear whether NFCD transmission service customers will cause the need for fewer \nNetwork Upgrades, and that further analysis is needed to determine whether discounts are \nappropriate.  Finally, Indicated TOs contend that Joint Co-Location Developers’ concerns \nthat the proposed NFCD transmission service rate will discourage industrial development \nare exaggerated and misplaced.  NOVEC similarly argues that it is not the Commission’s \nplace to subsidize certain industries at the expense of customers.863 \n In response to Vistra’s arguments about applying the rate for zonal Non-Firm \nPTPS to NFCD transmission service, Indicated TOs argue that doing so would be \nunreasonable because transmission customers have used Non-Firm PTPS exclusively to \nfacilitate the delivery of specific generation to the PJM border—not for internal use.864  \nNOVEC also rejects Vistra’s argument that NFCD transmission service should receive \nthe same rate as Non-Firm PTPS, arguing that it would not be appropriate to allow NFCD \ntransmission service the same discount as Non-Firm PTPS because the two products \nfundamentally differ.  Indicated TOs further argue that the discounted Non-Firm PTPS \nrate reflects historical use and was neither intended nor appropriate for NFCD \ntransmission service because NFCD transmission service is intended to be a limited, \nsupplemental service within PJM and does not facilitate the delivery of specific \ngeneration to specific load over a contract path.  Indicated TOs also contend that NFCD \n \n861 Id. at 12 (citing Market Monitor Response Brief at 6).  \n862 Indicated TOs Reply Brief at 19-21. \n863 NOVEC Reply Brief at 14. \n864 Indicated TOs Reply Brief at 13, 18-19."},{"page":186,"startToken":72057,"endToken":72423,"text":"Docket No. EL25-49-002, et al. \n- 186 - \ntransmission service is superior to Non-Firm PTPS because it has a superior curtailment \npriority. \n Indicated TOs reject Vistra’s argument that Indicated TOs’ proposal to credit the \nrevenues associated with NFCD transmission service to customers taking NITS and FCD \ntransmission service will create unjustified cost shifts among customer classes.865  \nIndicated TOs argue that these revenue credits are not subsidies but offsets that reduce \nthe amount paid by firm transmission service customers, which is appropriate because \ntransmission rates are designed to recover the fixed costs of building and maintaining the \ntransmission system to provide service to such customers.  In the absence of such credits, \nIndicated TOs argue that the transmission owners would over-recover their revenue \nrequirements.  Indicated TOs further argue that the revenue crediting mechanism is fully \nconsistent with previously approved mechanisms such as section 27A, which credits \nNon-Firm PTPS revenue to Network and Firm PTPS customers.   \n Industrials/Amtrak argue that NFCD transmission service cannot provide back-up \npower because it cannot be accessed during a BTMG generation facility outage until a \nrequest for it is submitted to and approved by PJM.866  Industrials/Amtrak further argue \nthat NFCD transmission service is also only available on an as-available basis and is \nsubject to both operational and automated interruption.867  Industrials/Amtrak explain \nthat, during a forced outage, a retail customer would be required to automatically curtail \nload until it submits a NFCD transmission service request and PJM approves that request. \n Industrials/Amtrak also argue that FCD transmission service can provide \nmaintenance power on a firm basis, but like back-up power, cannot do so at a cost lower \nthan gross load NITS because it implicitly assumes BTMG maintenance outages cannot \nbe scheduled to avoid peak periods.868 \nd. \nAnswer \n Geronimo Power argues that Indicated TOs’ proposed rate for NFCD transmission \nservice is unjust and unreasonable, will disincentivize Co-Located Loads from relying on \nNFCD transmission service, and lead to less efficient use of the transmission system.869  \n \n865 Id. at 31-32 (citing Vistra Response Brief at 23-25). \n866 Industrials/Amtrak Reply Brief at 8. \n867 Id. at 8 n.13. \n868 Id. at 9 n.16. \n869 Geronimo Power May 21 Answer at 8."},{"page":187,"startToken":72423,"endToken":72803,"text":"Docket No. EL25-49-002, et al. \n- 187 - \nGeronimo Power asserts that Indicated TOs offer no meaningful response to the question \nof what is a just and reasonable rate for NFCD transmission service.  Geronimo Power \nargues that the mere fact that Commission policy allows PJM transmission owners to \ncharge up to the firm rate in some cases does not mean that doing so here is just and \nreasonable.870  Geronimo Power avers that there should be little doubt that some form of \ndiscount must be applied as to NFCD transmission service. \ne. \nDetermination \n We agree with Indicated TOs that it is just and reasonable to base the rate for FCD \ntransmission service on the zonal NITS rates and underlying NITS revenue \nrequirements871 and direct the PJM transmission owners, as the replacement rate, to \nsubmit a compliance filing within 60 days of the date of issuance of this order that \nincludes Tariff revisions to effectuate this proposal.  Both FCD transmission service and \nNITS will provide a similar level of firm transmission service, and PJM will plan the \ntransmission system to ensure that it is able to provide both transmission services on a \nfirm basis.872   \n We find unjust and unreasonable PJM’s proposal to charge Eligible Customers \ntaking FCD or NFCD transmission services on behalf of Co-Located Loads for all \nancillary services other than regulation and black start based on total quantity of MWhs \nof energy delivered to the Co-Located Load.873  In the December Order, the Commission \nfound that Eligible Customers taking the new FCD transmission service on behalf of              \nCo-Located Loads must be charged for ancillary services based on the contract demand, \nwith the exception of regulation and black start services.874  Similarly, the Commission \nfound that Eligible Customers taking the NFCD transmission service on behalf of                \nCo-Located Loads must be charged for ancillary services on an as-reserved contract \ndemand basis, based on the reserved contract demand amount of transmission service, \nwith the exception of regulation and black start services.875   \n \n870 Id. at 9. \n871 Indicated TOs Initial Brief at 6. \n872 Id. at 8-9; December Order, 193 FERC ¶ 61,217 at PP 195, 208. \n873 PJM, Initial Brief, attach. A, Subpart B, §§ 714.5 & 715.4. \n874 December Order, 193 FERC ¶ 61,217 at P 209. \n875 Id. P 216."},{"page":188,"startToken":72803,"endToken":73279,"text":"Docket No. EL25-49-002, et al. \n- 188 - \n However, we find just and reasonable PJM’s proposal to charge Eligible \nCustomers taking FCD and NFCD transmission services on behalf of Co-Located Loads \nfor regulation and black start services based on gross demand, which is consistent with \nthe Commission’s findings in the December Order.  The Commission found in the \nDecember Order that “Eligible Customers that take the Firm Contract Demand \ntransmission service on behalf of Co-Located Loads must be charged for regulation and \nblack start services based on a gross demand basis, rather than the contract demand” \nbecause all Co-Located Loads rely on regulation and black start services to be served \nregardless of whether they are withdrawing energy from the transmission system.876  \nLikewise, the Commission found in the December Order that “Eligible Customers that \ntake the Non-Firm Contract Demand transmission service on behalf of Co-Located Loads \nuse and therefore should be charged for regulation and black start services based on a \ngross demand basis, rather than the reserved amount of transmission service.”877  \nTherefore, and consistent with our determination above to extend the three new \ntransmission services set forth in the December Order to Eligible Customers taking \nservice on behalf of load with BTMG that are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions, we direct PJM to \nsubmit a compliance filing within 60 days of the date of issuance of this order that revises \nits Tariff to:  (1) charge Eligible Customers taking FCD and/or NFCD transmission \nservices on behalf of Eligible Loads for all ancillary services other than regulation and \nblack start services based on their contract demand; and (2) charge Eligible Customers \ntaking FCD and/or NFCD transmission services on behalf of Eligible Loads for \nregulation and black start services based on their gross load.        \n We also find just and reasonable PJM’s proposal to charge Eligible Customers \ntaking FCD and/or NFCD transmission services certain administrative charges.  As PJM \nexplains, these are standard charges associated with use of the transmission system above \ntransmission service rates.878  For the same reason, we find just and reasonable PJM’s \nproposal to charge Eligible Customers taking FCD and/or NFCD transmission services \nredispatch costs to cover congestion-related costs, given that both of these services will \nbe pool-scheduled and can be served by generators redispatched to mitigate congested \ntransmission paths.  We thus direct PJM to submit a compliance filing, within 60 days of \nthe date of issuance of this order, that revises its Tariff to implement these charges.  \nConsistent with our determination above to extend the three new transmission services set \nforth in the December Order to Eligible Customers taking service on behalf of load with \nBTMG that are willing and able to limit their energy withdrawals from the transmission \n \n876 Id. P 209. \n877 Id. P 216.  \n878 PJM Initial Brief at 27."},{"page":189,"startToken":73279,"endToken":73718,"text":"Docket No. EL25-49-002, et al. \n- 189 - \nsystem under certain conditions, we further direct PJM to reflect this change in its \ncompliance filing. \n However, we are not persuaded that Indicated TOs’ proposal to set the maximum \nrate for NFCD transmission service equal to the rate for FCD transmission service is just \nand reasonable.  In the December Order, the Commission was clear that NFCD \ntransmission service would “provide an option for Eligible Customers seeking to use the \ntransmission system on behalf of a Co-Located Load in this more limited manner.”879  \nFurther, NFCD transmission service is non-firm and curtailed prior to FCD transmission \nservice and NITS.880  NFCD transmission service is therefore an inferior service to FCD \ntransmission service and NITS, and we find that the just and reasonable replacement rate \nhere should not charge the same maximum rate for these transmission services.  We \nacknowledge NOVEC’s argument that under PJM’s proposal, an Eligible Customer \nwould only take and pay for NFCD transmission service when the generator serving it is \nexperiencing an outage, so the same rate does not equate to the same cost to the Eligible \nCustomer.881  However, the same rate could apply to Eligible Customers taking the same \namount of FCD and NFCD transmission services.   \n  We also find that charging the same maximum rate for both FCD and NFCD \ntransmission services can undermine the benefits of the new NFCD transmission service \nfor other transmission customers.  Specifically, discounting non-firm transmission \nservices encourages transmission customers to use such services, which benefits all \ntransmission customers by maximizing use of the existing transmission system.  These \nbenefits accrue to other transmission customers in two ways.  First, the revenues related \nto NFCD transmission service will become a credit to, and thus offset, the transmission \nrevenue requirement, which is the basis for the rates that firm transmission customers are \ncharged.  Moreover, utilizing NFCD transmission service can avoid unnecessary Network \nUpgrades, the costs of which would likely be allocated to all firm transmission service \ncustomers.   \n Further, pricing NFCD transmission service at the same rate as FCD transmission \nservice is not consistent with cost causation principles or the December Order’s findings.  \nSpecifically, the Commission found that requiring an Eligible Customer taking \ntransmission service on behalf of Co-Located Load to take NITS on a gross demand basis \nwould be inefficient, and could necessitate costly transmission buildout and costs paid by \ntransmission customers that may not be necessary if Eligible Customers taking \ntransmission service on behalf of Co-Located Loads are willing and able to limit their \n \n879 December Order, 193 FERC ¶ 61,217 at P 214 (emphasis added). \n880 See infra Part VI.G. \n881 NOVEC Reply Brief at 10."},{"page":190,"startToken":73718,"endToken":74124,"text":"Docket No. EL25-49-002, et al. \n- 190 - \nenergy withdrawals from the transmission system under certain conditions and take a \ntransmission service that requires fewer or less costly Network Upgrades to provide.882  \nAs noted above, the Commission directed the creation of NFCD transmission service, \nfinding that it would provide an option for Eligible Customers taking service on behalf of \nCo-Located Loads that seek to use the transmission system in a more limited manner.883  \nThe December Order further found that Eligible Customers taking service on behalf of \nCo-Located Loads should be allowed to choose the transmission service that aligns with \ntheir use of the transmission system and therefore aligns the charges for service with the \nbenefits received.884  Indicated TOs’ proposal fails to comply with the directive in the \nDecember Order by charging the same rate for FCD and NFCD transmission services; the \nproposal does not align the charges for transmission service with the benefits received. \n Our finding here is also consistent with Commission precedent.  In Order No. 888, \nthe Commission determined that the rate for Non-Firm PTPS “is capped at the firm \nrate.”885  In response to Order No. 888, Duquesne sought clarification that the phrase “the \nnon-firm rate is capped at the firm rate” does not mean the Commission is deviating from \nits principles that non-firm transmission service must be priced in a manner that reflects \nthe interruptibility of the service and is economically efficient.886  The Commission \nclarified that the Firm PTPS transmission rate represents a maximum price for non-firm \ntransmission service and emphasized that “non-firm transmission prices should reflect the \ninterruptibility of the service and should promote efficient use of the transmission system, \nsubject to this price cap.”887  The Commission concluded that, “while in some \ncircumstances non-firm transmission rates may be set at a firm transmission rate level, \nthe Commission expects that non-firm transmission rates would, in most instances, be \npriced below the cap.”888 \n Thus, while the Commission recognized that the Firm PTPS transmission rate \ncould be a ceiling for the Non-Firm PTPS rate, the Commission also recognized that the \nrates should vary based on the quality of the transmission service.  Our finding here is \n \n882 December Order, 193 FERC ¶ 61,217 at P 199. \n883 Id. P 214. \n884 Id. P 199. \n885 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,743. \n886 Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,272. \n887 Id. \n888 Id."},{"page":191,"startToken":74124,"endToken":74598,"text":"Docket No. EL25-49-002, et al. \n- 191 - \nconsistent with Order No. 888 (i.e., that non-firm transmission service rates should \ngenerally be priced below firm transmission service rates).  Indicated TOs propose \nmaking the exception the rule and thus fail to justify that deviation.  Indicated TOs argue \nthat NFCD transmission service is a superior level of service compared to Non-Firm \nPTPS.  But, even assuming that statement is correct, it does not follow that NFCD \ntransmission service is therefore a similar level of service as FCD transmission service or \nNITS. \n We recognize that Indicated TOs state that they will consider offering discounts \nfor NFCD transmission service after an initial assessment period to determine whether a \ndiscount would encourage efficient use of the transmission system.  However, Indicated \nTOs miss the point of not only aligning the rate with the quality of the service provided, \nbut also designing a rate that incentivizes efficient non-firm uses of the transmission \nsystem.  It is counterintuitive to expect charging the full rate to inform an analysis of \nwhat discounts may be appropriate.  Therefore, we find that the possibility of offering \ndiscounts at some undefined time in the future is not sufficient to remedy our concerns \nwith their proposal.  Under that proposal, Indicated TOs would have no obligation to \nlower rates in the future and offer no transparency as to how or when that decision would \nbe made; moreover, they provide no compelling explanation as to why it would be just \nand reasonable to charge for NFCD transmission service at the FCD transmission service \nrate in the interim. \n We further disagree with NOVEC’s characterization of a lower rate for NFCD \ntransmission service as subsidized; as discussed in the body of this order, we find that a \nlower rate for NFCD transmission service is just and reasonable and consistent with cost \ncausation.  A lower rate for NFCD, as compared to FCD, transmission service will also, \nas NOVEC points out, incentivize transmission customers to use the service in areas \nwhere PJM can accommodate a large amount of NFCD transmission service.  This is \nexactly the point–Eligible Customers taking transmission service on behalf of Eligible \nLoads will be incentivized to take NFCD transmission service in areas where there is \nexcess transmission capacity, and the charges recouped from those customers will offset \nthe rates paid by firm transmission customers that funded the excess transmission \ncapacity.  Otherwise, this transmission capacity would remain unused and firm \ntransmission customers would pay more. \n NOVEC also argues that in areas where PJM can accommodate a large amount of \nNFCD transmission service, Co-Located Load could end up with the best of both worlds, \nwhere they are rarely curtailed but Eligible Customers taking transmission service on \ntheir behalf pay a subsidized rate for transmission service, with the option to switch to \nFCD transmission service or NITS if PJM can no longer accommodate the required level"},{"page":192,"startToken":74598,"endToken":74975,"text":"Docket No. EL25-49-002, et al. \n- 192 - \nof NFCD transmission service.889  We disagree that Eligible Customers could “simply \nswitch” to FCD transmission service or NITS if PJM can no longer accommodate the \nrequested level of NFCD transmission service.890  The process to request NITS remains \nunchanged, and we address the process to request FCD transmission service above.  But \nin either case, provision of firm transmission service will be studied, granted to the extent \nit can be done so reliably, and only available following construction of any required \nNetwork Upgrades.   \n With respect to Industrials/Amtrak’s argument that neither FCD nor NFCD \ntransmission services provide a cost-based back-up service for cogeneration QFs and \nsimilarly-situated retail customers,891 this argument is substantively similar to the \nargument the same parties raised on compliance, which is addressed supra.892  \nIndustrials/Amtrak contend that, because it would require payment for service based on \nthe contracted amount, FCD transmission service inherently assumes that forced outages \nor other reductions in electric output by all QFs will occur simultaneously, or during the \nsystem peak, or both, without any factual data to support that assumption.893  However, \nas noted above, this argument appears to conflate rates for sales of back-up power and \nrates for transmission service, rendering Industrials’/Amtrak’s concerns misplaced.   \n Industrials/Amtrak further argue that it would not comport with cost causation \nprinciples to require a FCD transmission service reservation for occasional back-up \npower needs and that NFCD transmission service will not be useful for back-up power \nbecause it must be requested in advance.894  Again, Industrials/Amtrak appear to conflate \nback-up power for QFs under PURPA with the subject of this proceeding, which is \ntransmission service taken by Eligible Customers serving Eligible Loads.  Further, \nIndustrials/Amtrak state that their concerns are for “whether retail customers can access \ncost-based . . . back-up service”895 but, with the exception of Eligible Customers that are \nretail customers taking unbundled transmission service, service available to retail \ncustomers is neither the subject of this proceeding nor within the Commission’s \n \n889 NOVEC Reply Brief at 12-13. \n890 Id.  \n891 Industrials/Amtrak Response Brief at 16-17. \n892 See supra Part V.A.3. \n893 Industrials/Amtrak Response Brief at 17 (citing Dauphinais Aff. ¶ 44). \n894 Id. at 18. \n895 Id. at 11 (emphasis added)."},{"page":193,"startToken":74975,"endToken":75410,"text":"Docket No. EL25-49-002, et al. \n- 193 - \njurisdiction.  However, to the extent Industrials/Amtrak refer to jurisdictional wholesale \ntransmission service when arguing that “examples exist of bespoke arrangements for \nindustrial and institutional customers that may require firm back-up needs,”896 we \ncontinue to find it just and reasonable that Eligible Customers taking NITS be charged on \na gross demand basis as explained in the December Order, with limited exceptions.897  \nNetwork Load has the right to be served from the transmission system at any time, and \nPJM and the transmission owners incorporate Network Load into their transmission \nplanning to ensure that they can fulfill their obligation to provide such service.  Thus, \nregardless of whether certain transmission customers that elect NITS to be able to take \ntransmission service on demand choose to only take such service occasionally, the system \nwill be planned to accommodate them at all times.  We therefore continue to find that the \nbenefits of NITS align with charging for NITS based on gross demand.  We further \nreiterate that, as discussed in this order, we have set aside, in part, the December Order to \nextend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions.898   \n Therefore, we direct the PJM transmission owners to submit, within 60 days of the \ndate of issuance of this order, a compliance filing with the Tariff charges for NFCD \ntransmission service in accordance with this order.  Specifically, the PJM transmission \nowners must propose a lower maximum rate or non-discriminatory discounts for the \nNFCD transmission service rate.  Moreover, the PJM transmission owners must ensure \nthat their proposed Tariff revisions are transparent as to how charges will be calculated \nfor an individual transmission customer.  Consistent with our determination above to \nextend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions, we \nfurther direct the PJM transmission owners to reflect this change in their compliance \nfiling.   \n5. \nOther  \na. \nInitial Briefs \n PJM states that any request for FCD and/or NFCD transmission service must \ncomply with Commission regulations for new service requests, and include several items \nspecific to these transmission services, such as a description of the supply characteristics \n \n896 Id. at 12. \n897 December Order, 193 FERC ¶ 61,217 at PP 186, 195. \n898 See supra Part IV.C.1.b.i."},{"page":194,"startToken":75410,"endToken":75826,"text":"Docket No. EL25-49-002, et al. \n- 194 - \nof the Co-Located Generator and the demand characteristics of the Co-Located Load.899  \nUpon receiving an application, PJM will evaluate whether the requested level of Contract \nDemand transmission service can be reliably provided.  PJM then explains that the \nEligible Customer must meet several conditions precedent, such as certifying that it is \nwilling and able to limit withdrawals from the transmission system when requested by \nPJM and providing PJM with an authorization or certification from its Relevant Electric \nRetail Regulatory Authority (RERRA) affirming that the Eligible Customer is authorized \nto provide energy to the Co-Located Load.  PJM also proposes to require that certain \nfacilities and necessary technical arrangements must be completed prior to \ncommencement of requested service. \n PJM next explains that, under the Service Agreement for Contract Demand \ntransmission service, service is presumed to continue without expiration, and that there \nare several bases for termination.900  For example, PJM explains that service can \nterminate on 42 months’ notice prior to the commencement of a delivery year, and PJM \nargues that this is appropriate because the contract demand level under FCD transmission \nservice will be accounted for in PJM’s capacity market.  PJM proposes circumstances \nwhereby PJM may terminate service for cause:  (1) the Eligible Customer breaches its \nobligations, such as materially changing the Co-Location Arrangement without PJM \nstudying it; or (2) the Eligible Customer is disqualified by failing to follow an operating \ninstruction to curtail or shed load, or after the misoperation, on more than one occasion, \nof any necessary control technologies or required protection systems (described further \nbelow).  \n PJM next proposes that the Eligible Customer designate the Co-Located Load and \nthe Co-Located Generator and provide the MW level of energy from the Co-Located \nGenerator dedicated to serving the Co-Located Load.901  For reliability purposes, PJM \nstates, the Eligible Customer must provide PJM with timely written or electronic notice \nof material changes in the demand characteristics of the Co-Located Load or the supply \ncharacteristics of the Co-Located Generator.  PJM maintains that necessary control \ntechnologies and protection systems for NFCD transmission service will be designed \nbased on the specific circumstances of each Co-Location Arrangement, and PJM’s ability \nto reliably operate the system could be impaired by any material changes to the control \ntechnologies or protection systems.  PJM proposes to prohibit an Eligible Customer from \nusing FCD transmission service for the sale of either capacity or energy to loads other \n \n899 PJM Initial Brief at 17-19. \n900 Id. at 20-22. \n901 Id. at 22-24."},{"page":195,"startToken":75826,"endToken":76227,"text":"Docket No. EL25-49-002, et al. \n- 195 - \nthan the Co-Located Load designated in its Service Agreement or the transmission \nservice to third parties.  \nb. \nResponse Briefs \n ODEC requests clarification regarding how PJM’s requirement that an Eligible \nCustomer taking transmission service on behalf of a Co-Located Load provide PJM with \nan authorization or certification from its RERRA which affirms that the Eligible \nCustomer is authorized to provide energy to the Co-Located Load would apply to a \ngeneration and transmission electric cooperative like ODEC.902  ODEC states that it is \nunclear whether PJM intends that ODEC, as an Eligible Customer, would need to provide \ncertification that ODEC’s member distribution cooperatives (which are the RERRA in \nMaryland and Delaware) have authorized ODEC to provide energy to the Co-Located \nLoad.  ODEC adds that, where the state regulatory agency is the RERRA, ODEC is \nunaware of a procedure whereby it would obtain authorization from the Virginia State \nCorporation Commission to provide energy to Co-Located Loads.  \n Constellation opposes PJM’s proposal that the Eligible Customer must submit an \nauthorization or certification from the RERRA affirming that the Eligible Customer is \nauthorized to provide energy to the Co-Located Load.903  Constellation argues that, if the \ngenerator is the Eligible Customer, it is unreasonable to require that generator to go to the \nstate commission for a special approval if the load is in a retail competition state.  \nConstellation maintains that the Eligible Customer need only show that the load will be \nserved by a transmission owner or licensed competitive retail supplier. \n Industrials/Amtrak argue that Co-Located Load on whose behalf an Eligible \nCustomer takes NFCD transmission service should have firm natural gas capacity or \nother adequate alternatives to be able to utilize the service.  Industrials/Amtrak argue this \nrequirement will prevent “misuse” of NFCD transmission service “by generators who \nhave the ability to operate but may want to rely on the grid when it appears to be more \neconomical for that generator.”904  Industrials/Amtrak explain that, from a resource \nadequacy perspective, policies surrounding NFCD transmission service should encourage \nloads to bring their own generation. \n Indicated TOs request that PJM add to section 710.1 of PJM’s illustrative tariff \nprovisions, as a condition precedent for receiving FCD or NFCD transmission service, a \nrequirement that the Eligible Customer satisfy any load-connection related requirements \n \n902 ODEC Response Brief at 6-7. \n903 Constellation Response Brief at 29. \n904 Industrials/Amtrak Response Brief at 24."},{"page":196,"startToken":76227,"endToken":76596,"text":"Docket No. EL25-49-002, et al. \n- 196 - \nimposed by the applicable PJM transmission owner.905  Indicated TOs argue that PJM \nshould add language to the list of information in section 710.2 of PJM’s illustrative tariff \nprovisions to be provided in an application for FCD and/or NFCD transmission service to \nthe effect that the customer has met applicable load interconnection study obligations.  \nIndicated TOs request that PJM add a placeholder section for listing required control \ntechnologies or protection systems to section 5.0 of PJM’s proposed Attachment F-4.906   \n Indicated TOs request that PJM clarify whether the use of “Delivery Point” in \nsection 710.2 subsection (iii) and subclause (i) of section 710.5 is appropriate in light of \nPJM’s proposed definition of Co-Located Load, which is based on facilities located on \nthe same side of the Point of Change in Ownership.907   \n Indicated TOs contend that PJM should clarify in section 711.3 of PJM’s \nillustrative tariff provisions or in PJM’s manuals what constitutes “material changes” for \npurposes of the annual information updates to be provided by Eligible Customers.908  \nIndicated TOs argue that PJM should revise section 712.2 of PJM’s illustrative tariff \nprovisions to require PJM to notify the affected PJM transmission owner(s) of any \nrequest for NFCD transmission service.  Indicated TOs argue that PJM should revise \nsection 713 of PJM’s illustrative tariff provisions to require that notice of any curtailment \nbe provided not only to the Eligible Customer but also to the affected PJM transmission \nowner or Electric Distribution Company.  \n Constellation recommends that, for Eligible Customers requesting transmission \nservice on behalf of Co-Located Load, if the customer facilities include an existing \ngenerator, a certification be required that the existing generator supports the transmission \nservice request.909  Constellation argues that this requirement would ensure the                      \nCo-Located Load is physically connected to the facilities of the existing or planned \nCustomer Facility.  Alliance promotes their framework for looking at how to responsibly \nenable large-load integration while preserving reliability, cost causation, and \naffordability.910  \n \n905 Indicated TOs Response Brief at 18. \n906 Id. at 19, 24. \n907 Id. at 18-19 n.41. \n908 Id. at 20-22. \n909 Constellation Response Brief at 30. \n910 Alliance Response Brief at 2."},{"page":197,"startToken":76596,"endToken":76947,"text":"Docket No. EL25-49-002, et al. \n- 197 - \nc. \nReply Briefs \n In response to parties’ comments, particularly those of Indicated TOs, PJM \nproposes certain revisions to its illustrative tariff language for FCD and NFCD \ntransmission services.911  Specifically, PJM notes that it proposes revisions to                 \nsection 711.3 to provide that the applicable transmission owner will be notified of \nmaterial changes to Co-Located Arrangements, as well as a reference to the PJM manuals \nfor further description of what would constitute a material change.  PJM further proposes \nchanges to section 713.1 to provide that PJM will notify the applicable transmission \nowners of any instruction to curtail Co-Located Load.  \n Constellation urges the Commission to deny Indicated TOs’ proposal to replace \n“Delivery Point” with “Point of Change in Ownership” in PJM’s requirements for \napplications for FCD and NFCD transmission services because it would risk uncertainty \nor delays for parties in Co-Location Arrangements.912  Constellation asserts that the \nTariff should use “Point of Interconnection,” consistent with the definition of Co-Located \nLoad. \n Since filing its initial brief, PJM states that it has determined that changes to \nAuction Revenue Rights rules must be modified to recognize that FCD transmission \nservice customers will contribute towards enhancing and maintaining the transmission \nsystem and should have the right to request Auction Revenue Rights.913  To effectuate \nthis modification, PJM proposes a revision to Operating Agreement, Schedule 1,              \nsection 7.4.2(d) and includes a new Operating Agreement, Schedule 1, section 7.4.2(l) to \ndetail the Auction Revenue Rights rules specific to Eligible Customers taking FCD \ntransmission service.914 \nd. \nDetermination \n We disagree with PJM that it is just and reasonable for the replacement rate to \nrequire Eligible Customers requesting FCD or NFCD transmission service to provide an \nauthorization or certification from its RERRA affirming that the Eligible Customer is \nauthorized to provide energy to the Co-Located Load.915  PJM does not provide any \n \n911 PJM Reply Brief at 62-63. \n912 Constellation Reply Brief at 9 (citing Indicated TOs Response Brief at 19). \n913 PJM Reply Brief at 65. \n914 Id. at 65-66. \n915 PJM Initial Brief at 18-19."},{"page":198,"startToken":76947,"endToken":77387,"text":"Docket No. EL25-49-002, et al. \n- 198 - \nexplanation or context for proposing this requirement, and it is not clear why an Eligible \nCustomer would need to go through this extra step under the Tariff to prove it is \nauthorized to serve load.  If an Eligible Customer that is not authorized to provide energy \nto load attempts to do so, that would be a matter for the RERRA’s enforcement \nmechanisms. \n We similarly disagree with Constellation that it is necessary to require Eligible \nCustomers requesting FCD or NFCD transmission service on behalf of Co-Located Load \nto include a certification from the Co-Located Generator, if it is an existing generator, to \nensure that the Co-Located Load is physically connected to the generator’s facilities.  The \nCommission already made clear that Co-Located Load must be “physically connected to \nthe facilities of an existing or planned Customer Facility on the Interconnection \nCustomer’s side of the Point of Interconnection to the PJM Transmission System.”916  If \nan Eligible Customer attempts to request FCD or NFCD transmission service on behalf of \na load that did not meet the definition of Co-Located Load, that should be referred to the \nCommission’s Office of Enforcement and Regulatory Accounting. \n Industrials/Amtrak argue that Co-Located Load on whose behalf an Eligible \nCustomer takes NFCD transmission service should have firm natural gas capacity or \nother adequate alternatives to be able to utilize the service.917  Industrials/Amtrak explain \nthat such a requirement would “avoid misuse of the [NFCD transmission] service by \ngenerators who have the ability to operate but may want to rely on the grid when it \nappears to be more economical for that generator.”  The December Order contained no \nsuch limitation and Industrials/Amtrak have failed to justify adding it here.  Specifically, \nthe December Order stated that NFCD transmission service would reflect Eligible \nCustomers taking service on behalf of Co-Located Loads that may not “necessarily plan \nto withdraw energy from the transmission system on a regular basis” but “still seek to \nwithdraw energy from the transmission system from time to time when transmission \ncapacity is available and not needed by firm customers.”918  The December Order thus \ncontemplates that NFCD transmission service would be an option for Eligible Customers \ntaking transmission service on behalf of Co-Located Load, not a mandate. \n Indicated TOs request that the Commission direct as part of the replacement rate \nrequirements related to Eligible Customers satisfying requirements related to load \n \n916 December Order, 193 FERC ¶ 61,217 at P 1 & n.3; February Order, 190 FERC \n¶ 61,115 at P 3 & n.4. \n917 Industrials/Amtrak Response Brief at 24. \n918 December Order, 193 FERC ¶ 61,217 at P 214."},{"page":199,"startToken":77387,"endToken":77761,"text":"Docket No. EL25-49-002, et al. \n- 199 - \ninterconnections.919  Indicated TOs have not explained why these requirements are \nnecessary, and so we decline to make them a part of the replacement rate at this time.  \nHowever, we agree with Indicated TOs’ request that PJM add a placeholder section for \nlisting necessary control technologies and/or protection systems to section 5.0 of PJM’s \nproposed Attachment F-4.  \n We also find PJM’s proposal to allow FCD transmission service customers to \nrequest Auction Revenue Rights in stage 2 of the allocation process to be just and \nreasonable.  Given the underlying design of the FCD transmission service, we find the \npresumption that FCD transmission service customers contribute towards enhancing and \nmaintaining the transmission system on par with other Firm PTPS transmission \ncustomers to be reasonable.  PJM’s proposal provides FCD transmission service \ncustomers an equivalent opportunity to request Auction Revenue Rights.  We direct PJM \nto submit a compliance filing within 60 days of the date of issuance of this order to revise \nits Tariff consistent with this replacement rate.  Consistent with our determination above \nto extend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions, we \nfurther direct PJM to reflect this change in its compliance filing. \nB. \nAdditional Charge for Eligible Customers Taking FCD and/or NFCD \nTransmission Service \n1. \nDecember Order \n As part of the paper hearing, the Commission asked the parties:  \nShould the rate paid by an Eligible Customer on behalf of a \nCo-Located Load taking only the new Non-Firm Contract \nDemand transmission service that elects to not reserve any \namount of that service for a period of time (e.g., one month) \nreflect not only charges for regulation and black start \nservices, but also an additional charge given that regulation \nand black start services could not be provided without the \ntransmission system?  If so, how should that additional charge \nbe determined? \n In addition, the Commission asked:  \nShould the rate paid by an Eligible Customer on behalf of a \nCo-Located Load taking only a de minimis amount of the new \n \n919 Indicated TOs Response Brief at 18-19."},{"page":200,"startToken":77761,"endToken":78178,"text":"Docket No. EL25-49-002, et al. \n- 200 - \nFirm or Non-Firm Contract Demand transmission services \nreflect not only (i) charges for regulation and black start \nservice and (ii) the transmission service charges for that            \nde minimis amount of service, but also an additional charge \nreflecting that the Co-Location Arrangement is physically \nconnected and synchronized to the PJM transmission system?  \nIf so, how should that additional charge be determined? \n2. \nInitial Briefs \n Indicated TOs propose to charge a Grid Reliance Charge to Eligible Customers \ntaking FCD or NFCD transmission service based on the difference between either the \ncontract amount of FCD transmission service, or the reserved amount of NFCD \ntransmission service, and the customer’s gross on-site load.920  Indicated TOs explain that \nthe Grid Reliance Charge is designed to reflect the costs of using the transmission system \nto deliver black start and regulation services, as well as the inherent benefit that all \ncustomers receive through their synchronization to and reliance on the transmission \nsystem.  Indicated TOs state that the Grid Reliance Charge also recognizes the costs \nassociated with the operations, maintenance, and other activities that Indicated TOs will \nneed to perform for the transmission system and to accommodate the increased number \nof protection schemes required for Co-Location Arrangements.  Indicated TOs propose to \ncalculate this charge for each zone based on an average fixed percentage of the portion of \ntransmission depreciation and operations and maintenance expense associated with \nproviding grid reliance services, and to apply that percentage to each transmission \nowner’s annual revenue requirement.921  Indicated TOs argue that it is appropriate to use \nannual depreciation and operations and maintenance expenses because these expenses \nbest capture the portions of a transmission owner’s revenue requirement relating to the \nongoing reliable operation of the transmission system.  Indicated TOs propose an initial \npercentage of 25.8%, subject to adjustment every five years.  \n In further justifying the Grid Reliance Charge, Indicated TOs assert that                    \nCo-Located Load and its associated Co-Located Generator benefit from the existence and \nreliable operation of the transmission system because they are electrically connected to \nthe transmission system, and should contribute to paying the costs of continuing to \nreliably operate the system regardless of the amount of energy withdrawn.  Indicated TOs \ncontend that a large Co-Location Arrangement with zero MW of FCD or NFCD \ntransmission service still depends on the grid for the delivery of various ancillary services \nand a suite of synchronization support services, such as stable frequency, inertia, stability \n \n920 Indicated TOs Initial Brief at 14. \n921 Id. at 14-16."},{"page":201,"startToken":78178,"endToken":78591,"text":"Docket No. EL25-49-002, et al. \n- 201 - \nservices, fault current capability, and ride-through and protection coordination.  Indicated \nTOs argue that the Commission has long recognized that an integrated transmission \nsystem provides broad reliability benefits to all customers of the system, and this \nrecognition has guided Commission decisions on ratemaking and cost allocation.922 \n Indicated TOs maintain that their proposed methodology for the Grid Reliance \nCharge is a just and reasonable way to estimate with an appropriate level of precision the \nbenefits to Co-Located Load from relying on the grid while ensuring this charge can be \nfairly and efficiently implemented.923  Indicated TOs state that they have included \ndetailed testimony on the proposed methodology, and they highlight that the allocator is \nbased on costs included in transmission plant and transmission operations and \nmaintenance FERC accounts.924  Indicated TOs contend that their proposal is \nconservative in a number of respects, for example, they exclude amortization and general \nplant depreciation, as well as administrative and general expenses.  Indicated TOs explain \nthat the allocator will be multiplied by each transmission owner’s rate for NITS and FCD \ntransmission service, resulting in an “unadjusted” Grid Reliance Charge rate.  Indicated \nTOs further explain that they propose to multiply this unadjusted rate by a ratio that \naccounts for the difference between the demand used to account for the NITS and FCD \ntransmission service rate and the gross load for Eligible Customers on behalf of                       \nCo-Located Load, resulting in the final Grid Reliance Charge for each zone.  Indicated \nTOs propose to update the allocation percentage every five years to ensure rate stability \nand avoid the allocators becoming stale.  Indicated TOs propose to apply the revenues \nfrom the Grid Reliance Charge as credits to NITS and FCD transmission service \ncustomers in the relevant zone to avoid double recovery or inappropriate cost shifts.  \n3. \nResponse Briefs \na. \nBasis for an Additional Charge \n ODEC and NOVEC support Indicated TOs’ proposal for a Grid Reliance Charge \nto be applied to customers taking FCD and NFCD transmission service.925  ODEC argues \nsuch a charge ensures that Co-Located Loads pay their “fair share” of costs that are \ncommensurate with the benefits Co-Located Loads receive from the transmission system, \nincluding the costs associated with delivery of black start and regulation services.  \n \n922 Id. at 15-16 (citing W. Mass. Elec. Co. v. FERC, 165 F.3d 922, 927 (D.C. Cir. \n1999)). \n923 Id. at 16. \n924 Id. at 16-18. \n925 ODEC Response Brief at 10; NOVEC Response Brief at 9."},{"page":202,"startToken":78591,"endToken":79024,"text":"Docket No. EL25-49-002, et al. \n- 202 - \nNOVEC similarly asserts that Co‑Located Load depends on the transmission system to \ndeliver black start and regulation services, the charges for which a delivery component is \nnot included.  NOVEC argues that without the Grid Reliance Charge, a Co-Located Load \nthat reserved no FCD or NFCD transmission service would be a free rider, as it would \nbenefit from the payments of existing transmission customers to maintain the \ntransmission system without making any contribution towards it.  \n Geronimo Power argues that Indicated TOs have not demonstrated that their \nproposed Grid Reliance Charge reflects Co-Located Loads’ actual impact on or benefits \nfrom interconnection with the transmission system and is consistent with cost causation \nprinciples.926  Further, Geronimo Power states that Indicated TOs have failed to \ndemonstrate that there is a separate delivery component to black start and regulation \nservices and that, if there were such a component, Indicated TOs have not explained why \nit would not be unduly discriminatory to apply it only to Co-Located Loads.   \n Vistra argues that Indicated TOs fail to address the nuances in the Commission’s \npaper hearing questions on additional charges or the actual ways that NFCD transmission \nservice customers might rely on the grid.927  Vistra asserts that the Commission’s \nquestions illustrate that customers could use NFCD transmission service in different ways \nbut transmission owners would impose the same charge regardless.  Vistra maintains that, \nwhile Indicated TOs argue that Co-Located Loads are all synchronized to the grid, \nsynchronization is not, itself, a service.  Vistra alleges that, in contrast to the \nCommission’s long-standing policy that transmission providers offer and price ancillary \nservices separately, Indicated TOs create a new service for what appears to be an \nundefined ancillary service (i.e., grid reliance) to cover a suite of synchronization support \nservices.  Vistra argues that it is not consistent with cost causation principles to impose \nthe same grid reliance charge for very different types of grid reliance.  Vistra contends \nthat the Commission did not prejudge whether or when a grid reliance charge is necessary \nand that the Commission could conclude no such charge is necessary for customers \ntaking zero MWs or a de minimis amount of the new transmission services.  \n Industrials/Amtrak argue that, as an as-available service, there should be no \nstandby fee charging NFCD transmission service customers for access to the transmission \nsystem that is not guaranteed.  Instead, Industrials/Amtrak contend that customers should \nbe charged based on actual use on an hourly basis.928 \n \n926 Geronimo Power Response Brief at 10-11, 13-14. \n927 Vistra Response Brief at 19-21.  \n928 Industrials/Amtrak Response Brief at 24."},{"page":203,"startToken":79024,"endToken":79410,"text":"Docket No. EL25-49-002, et al. \n- 203 - \nb. \nMethodology for Determining Additional Charge \n NOVEC states that the proposed Grid Reliance Charge is just and reasonable \nbecause it is limited to depreciation and operations and maintenance, and conservatively \nexcludes a return on rate base and associated income taxes.929  NOVEC also notes that \nbecause revenues earned from the Grid Reliance Charge are returned to NITS and FCD \ntransmission service customers as a revenue credit, the structure avoids any risk of double \nrecovery. \n Alliance argues that the additional charge question is important and should be \nresolved in a way that protects other customers from unjustified cost shifts.930  Alliance \ntakes no position on a specific dollar figure; instead, it recommends that any additional \ncharge reflect the contributions of load that have efficient operations or verified load \nflexibility through reductions in their cost obligations.    \n Regarding Indicated TOs’ argument that the Grid Reliance Charge will also cover \ncosts associated with the protection schemes for Co-Located Load, Geronimo Power \nargues there is no reason to believe transmission owners will bear any such costs that \ncould not be addressed in interconnection agreements.931 \n Vistra argues that, even if some charge is appropriate, Indicated TOs have not \njustified their proposed rate.932  Vistra contends that it is unreasonable to propose that a \ncustomer that never takes transmission service receives benefits approximating 25.8% of \nthe transmission owners’ revenue requirement.  Vistra highlights that only 0.5% of PJM’s \nmonthly total billings are related to black start and regulation charges and that, to the \nextent an NFCD transmission service customer never reserves transmission service relies \non the transmission system, that reliance is for the sole purpose of receiving black start \nand regulation service.  As such, Vistra argues, the percentage of PJM’s total monthly \nbillings that relates to black start and regulation charges is a reasonable proxy for the \namount of transmission system costs that are associated with use of the grid to deliver \nblack start and regulation service.  \n Vistra also contends that Indicated TOs’ proposal conflicts with the Commission’s \ntransmission pricing policy because it disincentivizes efficiency and focuses on \nreallocating a large share of sunk costs.  Moreover, Vistra contends, Indicated TOs’ \n \n929 NOVEC Response Brief at 10. \n930 Alliance Response Brief at 4.  \n931 Geronimo Power Response Brief at 14. \n932 Vistra Response Brief at 21-23."},{"page":204,"startToken":79410,"endToken":79805,"text":"Docket No. EL25-49-002, et al. \n- 204 - \nproposal would create significant and unjustified cost shifts between NFCD transmission \nservice customers and Network Customers.933  Vistra suggests it is not clear what \ntransmission owners, which are major Network Customers, will do with the bill credits \nand that it is not a foregone conclusion that they will pass savings onto retail customers.  \n Constellation contends that Indicated TOs’ proposed Grid Reliance Charge rests \non an unsound methodology that violates cost causation principles.934  Constellation \nrequests that the charge be recalculated based on the “minimum system” method.  \nConstellation asserts that Indicated TOs both exclude reasonable costs and include \nunreasonable costs in the grid reliance capability operations and maintenance and provide \nvery little justification for their proposal.  Moreover, Constellation argues that Indicated \nTOs inappropriately include full depreciation costs for a variety of transmission \ncomponents that are sized to meet actual peak demand requirements of the PJM system, \neven though customers paying the Grid Reliance Charge do not withdraw energy from \nthe PJM system.  In support of the minimum system method, Constellation argues it is \ndesigned to calculate the set of costs that a Co-Located Load that benefits from the \nexistence of wires but imposes no demand on the grid should share.  Constellation \nexplains that its method involves determining the minimum size of all electricity system \ncomponents that could be used by the utility to recreate its system and connect each \ncustomer to the grid, and then applying this fraction to each transmission owners’ NITS \nrate.   \n4. \nReply Briefs \na. \nBasis for an Additional Charge \n Indicated TOs contend that being connected to the grid provides obvious benefits \nin terms of the ability to access resources that are not co-located with load.935  Indicated \nTOs further argue that being connected to the grid includes benefits like delivering \nancillary services and essential reliability services, such as frequency support, inertia, \nvoltage stability, fault current capability, ride-through and protections coordination, and \nproviding sufficient short-circuit capability.  Indicated TOs state that they are unaware of \nany existing or proposed Co-Located Load customers that are choosing to island their \nload and on-site generation, and they infer from that fact that Co-Located Loads should \n \n933 Id. at 23-25. \n934 Constellation Response Brief at 25-28. \n935 Indicated TOs Reply Brief at 22 (citing Joint Blazunas/Schafer/Hammer \nRebuttal Test. at 16); see also Joint Blazunas/Schafer/Hammer Rebuttal Test. at 31."},{"page":205,"startToken":79805,"endToken":80146,"text":"Docket No. EL25-49-002, et al. \n- 205 - \nshare in the basic costs of operating and maintaining the grid upon which they rely.936  \nIndicated TOs further argue that an additional charge is appropriate because ancillary \nservices such as black start and regulation provide no value without the ability to access \nthe transmission system to obtain them.937 \nb. \nMethodology for Determining Additional Charge \n Indicated TOs defend their proposed methodology, arguing that it produces a more \nconservative result focused on recovery of the costs necessary to support the ongoing \nreliable operation of the transmission system, rather than a return on investment.938  \nIndicated TOs criticize Constellation’s proposal to use the “minimum system” method, \narguing that it is not used at the transmission level and lacks any correlation between the \nbenefits Co-Located Load receives and the electrical connection of customers.  Indicated \nTOs also reject Vistra’s proposed methodology, arguing that Vistra draws no connection \nbetween the percentage of billed revenue for regulation and black start and the costs of \nthe transmission system to deliver those services and the benefits associated with grid \nconnection.  \n NOVEC argues that Constellation’s minimum system proposal is not cost-aligned \nwith the use of black start service or regulation service because black start service relies \non the existence and durability of the transmission system in a way that Constellation’s \nminimum system methodology does not capture.939  NOVEC further argues that the ratio \nmethod advanced by Vistra arbitrarily confuses the cost of black start and regulation \nservices with the cost of the transmission infrastructure necessary for customers to \nreceive them.  \n Joint Co-Location Developers argue that the proposed Grid Reliance Charge is \nderived from an unsound methodology that violates cost causation principles.940  Joint \nCo-Location Developers argue that the Commission should direct the PJM transmission \n \n936 Indicated TOs Reply Brief at 22. \n937 Id. at 22-23. \n938 Id. at 24, 26-27, 29. \n939 NOVEC Reply Brief at 23, 26.  \n940 Joint Co-Location Developers Reply Brief at 3 (citing Constellation Response \nBrief at 25; Geronimo Power Response Brief at 9-15; Vistra Response Brief at 18-23)."},{"page":206,"startToken":80146,"endToken":80496,"text":"Docket No. EL25-49-002, et al. \n- 206 - \nowners to adopt the alternate cost calculation framework proposed by Constellation, \nwhich follows the Commission’s cost causation principles.941 \n Industrials/Amtrak argue that the proposed Grid Reliance Charge fails to reflect \nhow different customers actually rely on the transmission system and would result in \ncustomers that take little or no energy from the grid subsidizing traditional network \ncustomers, violating cost causation principles.942  Industrials/Amtrak argue that NFCD \ntransmission service should not be charged a standby fee such as the Grid Reliance \nCharge, as NFCD transmission service does not provide any guaranteed availability.   \n5. \nAnswers \n Constellation contends that Indicated TOs’ proposal would force customers that do \nnot impose demand on the transmission system to pay for transmission components sized \nto serve peak load, while also arbitrarily excluding costs related to rate of return and \ntaxes.943  Constellation defends its proposed minimum system methodology. \n Geronimo Power asserts that, while it does not oppose the concept of a grid \nreliance charge, Indicated TOs continue to fail to show that it is necessary and reflects \nCo-Located Loads’ actual grid impact or the transmission service they will receive.944  \nGeronimo Power argues that Indicated TOs’ proposal to assess a charge for the delivery \nof black start and regulation service when other customers are not required to pay a \nseparate delivery charge is unjust, unreasonable, and unduly discriminatory or \npreferential.945  Geronimo Power maintains that Indicated TOs have not demonstrated \nthat the purported synchronization benefits will accrue to the same degree for Co-Located \nLoad that is being primarily supplied by on-site generation.946 \n Indicated TOs respond to Constellation’s argument that the Indicated TOs’ \nproposed charge is based on the cost of the transmission system to serve peak demand \nrather than to delivery ancillary services, arguing that the purpose of the Grid Reliance \n \n941 Id. at 4 (citing Constellation Response Brief, attach. 1, (Testimony of Zachary \nMing), at 14-15). \n942 Industrials/Amtrak Reply Brief at 11-12, 14. \n943 Constellation May 11 Answer at 11-12. \n944 Geronimo Power May 21 Answer at 10. \n945 Id. at 11. \n946 Id. at 12."},{"page":207,"startToken":80496,"endToken":80905,"text":"Docket No. EL25-49-002, et al. \n- 207 - \nCharge is not only to recover costs to deliver ancillary services, but to ensure Co-Located \nLoad customers pay their fair share of the transmission system as it exists and the \nassociated benefits that it provides to all interconnected customers, including essential \nreliability services.947  Indicated TOs maintain that their proposed charge does so by \ncalculating the annual depreciation and operations and maintenance expenses that \nconstitute a reasonable proxy for the costs of providing those benefits.  Indicated TOs \nassert that Constellation’s minimum system method is only appropriate for and applicable \nto distribution level service. \n6. \nDetermination \n In the December Order, the Commission sought briefing on whether the \nCommission should establish an additional charge for Eligible Customers on behalf of a \nCo-Located Load that elects to not reserve any amount of transmission service or only a \nde minimis amount of transmission service.948  In response, parties submitted briefs \naddressing a range of issues, including, among others:  (1) what potential benefits \nEligible Customers that are synchronized to the transmission system might receive when \nnot drawing energy from the transmission system; (2) whether those potential benefits \nwarrant an additional charge or are adequately addressed through any transmission \nservice charges that the Eligible Customer is already responsible for; and (3) proposed \nrates for such a charge and whether those proposed rates are consistent with cost \ncausation principles.   \n We have considered that record and conclude that it does not adequately \nsubstantiate the need for an additional charge at this time or how such a charge should be \ncalculated and assessed.  In particular, the record contains insufficient description of the \npotential nature or magnitude of the cited benefits or the potential costs that transmission \nproviders or owners may incur when providing these benefits to Eligible Customers on \nbehalf of Co-Located Loads.  For example, Indicated TOs state that, even where an \nEligible Customer has requested FCD or NFCD transmission service for 0 MW, a large \nCo-Location Arrangement will still depend on the transmission system for a suite of \nsynchronization support services, such as stable frequency, inertia, stability services \n(damping, angle stability), fault current capability, and ride-through and protection \ncoordination.949  However, beyond briefly listing such benefits, the record lacks \nspecificity regarding what these services are, what costs they involve, and how they \n \n947 Indicated TOs May 28 Answer at 11. \n948 December Order, 193 FERC ¶ 61,217 at P 219, questions 3 and 4. \n949 Indicated TOs Initial Brief at 15."},{"page":208,"startToken":80905,"endToken":81297,"text":"Docket No. EL25-49-002, et al. \n- 208 - \nbenefit Eligible Customers on behalf of Co-Located Loads.  Accordingly, we decline to \nestablish an additional charge at this time.  \n Nonetheless, we recognize that the new transmission services created in this \nproceeding could raise novel questions regarding application of cost causation principles, \nparticularly if, in practice, many Eligible Customers taking the new transmission services \non behalf of Eligible Load elect to take a de minimis or not reserve any amount of \ntransmission service.  We believe that experience with the actual use of these new \ntransmission services will improve our understanding of any potential issues and inform \nwhether future action is needed.  To the extent parties identify such issues resulting from \nhow Eligible Customers on behalf of Eligible Load use the new transmission services, \nthey may submit filings under FPA section 205 or complaints under FPA section 206, as \nappropriate, and the Commission will consider the records before us at that time. \nC. \nInterconnection Requirements and Operational Practices for \nNecessary Control Technologies and/or Protection Systems \n1. \nInitial Briefs \n PJM states that NERC has established reliability standard requirements for the \nvarious forms of control technologies that may be relied upon for grid stability to which \nEligible Customers are expected to adhere.950  PJM explains that the PJM manuals and, \nas applicable, NERC reliability standards will contain the interconnection requirements \nand operational practices needed for necessary control technologies and protection \nsystems to maintain system reliability if a Co-Located Load or Co-Located Generator \ntrips offline.  PJM asserts that the NERC reliability standards form baseline \ninterconnection requirements and operational practices, and the PJM manuals provide \nadditional details and, at times, more stringent standards for remedial action schemes.  \nPJM describes an illustrative list of interconnection requirements and operational \npractices in its brief, including NERC Reliability Standards PRC-012-2 and PRC-017-1, \nPJM Manual 3, section 1.8, and PJM Manual 7, section 17.2.951 \n Indicated TOs do not offer a specific proposal at this time, but they highlight \nconcerns and key elements relating to interconnection, planning, and operational \npractices for the new transmission services.952  Indicated TOs assert that it is novel to use \nmultiple special protection schemes/remedial action schemes to protect the grid from \nlarge amounts of on-site load exceeding their contractual withdrawal limitations.  \n \n950 PJM Initial Brief at 56-57. \n951 Id. at 57-58. \n952 Indicated TOs Initial Brief at 22-26."},{"page":209,"startToken":81297,"endToken":81729,"text":"Docket No. EL25-49-002, et al. \n- 209 - \nIndicated TOs recommend that all special protection schemes and remedial action \nschemes be fully redundant to protect against the failures of protection schemes.  \nIndicated TOs recommend that the Eligible Customer taking FCD transmission service, \nNFCD transmission service, or Interim NITS on behalf of Co-Located Load pay for   \nPJM- and transmission owner-administered studies to ensure any special protection \nschemes or remedial action schemes can mitigate the risks of potential failure modes.  \nIndicated TOs request the option to review and agree to curtailment procedures and \noperational control mechanisms.  Indicated TOs argue that all special protection schemes \nand remedial action schemes must meet PJM and transmission owner technical criteria.   \n Indicated TOs state that the Commission should consider requiring more frequent \ntesting of special protection schemes and remedial action schemes than is currently \nrequired by NERC reliability standards.  Indicated TOs argue that they and PJM should \nreceive test results of protection schemes and that any inadequate special protection \nschemes or remedial action schemes should be updated accordingly.  Indicated TOs argue \nthat they and PJM should be permitted to implement and enforce reasonable limits on the \ntotal amount of load that can be covered by special protection schemes or remedial action \nschemes.  Indicated TOs request that the Commission direct NERC to establish \nrequirements so that Eligible Customers taking FCD transmission service, NFCD \ntransmission service, or Interim NITS on behalf of Co-Located Loads would be \nresponsible for meeting relevant NERC reliability standards.  Indicated TOs contend that \nthe Commission must strictly enforce compliance with NERC Reliability Standard   \nPRC-012-2 (Remedial Action Schemes), which includes nine requirements to address all \naspects of remedial action schemes.  Indicated TOs also emphasize that they will need to \nperform load integration studies for any Co-Located Load, as they currently do for large \nload customers, which could involve analysis of whether upgrades are needed to \naccommodate the physical gross load behind the Point of Interconnection.  \n2. \nResponse Briefs \n Vistra opposes Indicated TOs’ request to implement and enforce limits on the \namount of load that can be covered by special protection schemes, including in certain \nareas.953  Vistra expresses concern that this limit could lead to undue discrimination, and \nargues that if the Commission permits such limits, the Commission must ensure \nstandardized and transparent guidelines are in place.  Vistra contends that Indicated TOs’ \nproposal would violate the comparability requirement because PJM’s existing procedures \ndo not include location-based restrictions for remedial action schemes.  Vistra also \nopposes Indicated TOs’ proposal to own special protection schemes, arguing that it \nwould needlessly raise the cost of transmission service.  \n \n953 Vistra Response Brief at 27-28, 31."},{"page":210,"startToken":81729,"endToken":82087,"text":"Docket No. EL25-49-002, et al. \n- 210 - \n NOVEC states that at a minimum, PJM’s proposal to incorporate NERC reliability \nstandards is just and reasonable.954  NOVEC also states that the Commission should \ndirect NERC to establish registration requirements for Co-Located Loads so that they can \nbe responsible for meeting NERC reliability standards.  \n NOVEC states that special protection schemes should be fully redundant and that \nthe applicable transmission owner should be able to establish technical criteria for the \ninterconnection of Co-Located Load.955  NOVEC argues that transmission owners are \nfamiliar with the operating characteristics of their own systems, and any criteria should \nbe flexible enough to include reasonable requirements the transmission owners believe \nare necessary to protect the transmission system. \n Industrials/Amtrak argue that, to the extent that special protective schemes are \nrequired by the Commission for access to NFCD transmission service, the requirements \nshould account for realistic on-site constraints, such as certain load/generation \nconfigurations that allow only a limited amount of draw from the transmission system.956 \n In response to PJM’s Initial Brief, Indicated TOs argue that any Eligible Customer \ntaking any of the new transmission services (including FCD transmission service) ought \nto comply with requirements to implement necessary control technologies and protection \nsystems to ensure that a Co-Located Load does not exceed its specified level of \nservice.957  Indicated TOs therefore request that PJM add language to section 708(c) of \nPJM’s illustrative tariff provisions making clear that Interim NITS, FCD transmission \nservice, and NFCD transmission service are contingent on the implementation of \nnecessary control technologies and protection systems, where applicable.  Relatedly, \nIndicated TOs propose to strike the phrase “only in the case of Non-Firm Contract \nDemand Transmission Service” from subclause (ii) of section 710.5 of PJM’s illustrative \ntariff provisions.958  Similarly, Indicated TOs contend that PJM should revise                  \nsection 713.6 of PJM’s illustrative tariff provisions so as to not limit the requirement to \nestablish necessary control technologies and protection systems to NFCD transmission \nservice.  \n \n954 NOVEC Response Brief at 16-17. \n955 Id. at 17. \n956 Industrials/Amtrak Response Brief at 25. \n957 Indicated TOs Response Brief at 7-8, 17-18. \n958 Id. at 19-20, 22."},{"page":211,"startToken":82087,"endToken":82454,"text":"Docket No. EL25-49-002, et al. \n- 211 - \n Indicated TOs argue that PJM should include language in the Tariff making clear \nthat necessary control technologies and protection systems may be required on both the \ncustomer’s and the transmission owner’s side of the Point of Interconnection, including \nin section 710.5 of PJM’s illustrative tariff provisions.959   \n Indicated TOs argue that it is important for PJM to work with the PJM \ntransmission owners and other stakeholders to develop details on the requirements \nassociated with control technologies and protection systems necessary to ensure that    \nCo-Located Loads do not exceed their relevant withdrawal limitations.960 \n Constellation seeks clarification that PJM only intends to apply existing \nrequirements in Manual 3 to Co-Location Arrangements, not to establish new \nrequirements solely for such arrangements.961  Constellation also seeks clarification that \nPJM does not intend to restrict the use of permanent system protection schemes. \n Constellation supports Indicated TOs’ first four recommendations, subject to \nclarification to avoid delay and discrimination.962  For example, while Constellation \nsupports requiring full redundancy for special protection schemes and remedial action \nschemes, Constellation argues that it is not clear what full redundancy means.  \nConstellation opposes the Indicated TOs’ remaining recommendations as unsupported \nand discriminatory.  \n3. \nReply Briefs \n Indicated TOs state that they agree that the transmission owner and customer each \nmay own the circuit breaker(s) and protection systems at their respective facilities and, in \nresponse to Constellation, state that the number of breakers will be determined by the \ntransmission owner’s and customer’s design practices and budgets, as well as the \n \n959 Id. at 8-9, 20. \n960 Id. at 9. \n961 Constellation Response Brief at 21. \n962 Id. at 22-25.  More specifically, Constellation supports, subject to clarification, \nIndicated TOs’ recommendations that:  (1) all special protection schemes and remedial \naction schemes be fully redundant; (2) customers should pay for PJM and transmission \nowner-administered studies to ensure any special protection schemes and remedial action \nschemes can effectively mitigate the risks of potential failure modes; (3) transmission \nowners have the option to review and agree to any customer load curtailment procedures \nor operational control mechanisms; and (4) all special protection schemes and remedial \naction schemes must fully meet PJM and transmission owner technical criteria.  Id."},{"page":212,"startToken":82454,"endToken":82773,"text":"Docket No. EL25-49-002, et al. \n- 212 - \ntransmission owner’s technical criteria.  Indicated TOs disagree with Constellation’s \nassertion that new technical criteria specific to Co-Located Load need not be added to \nPJM Manual 3.  Indicated TOs argue that such revisions or additions may be unavoidable \ndue to the technical characteristics of Co-Located Load and contend that PJM and the \nPJM transmission owners should not be restricted from developing and implementing \ncriteria applicable to Co-Located Load as a class if warranted by reasonable technical \ndifferences.963   \n Indicated TOs argue that Constellation’s request for the Commission to reject \ncertain recommendations made by Indicated TOs is without merit.  Indicated TOs reject \nConstellation’s claim that these recommendations treat Co-Located Loads differently \nwithout legitimate basis and explain that certain transmission owners already require \nprotection on their facilities in certain circumstances.964 \n Indicated TOs argue that Vistra provides no convincing reason for the \nCommission to reject Indicated TOs’ recommendation for reasonable limits on the \namount of load covered by special protection schemes/remedial action schemes in \nspecific geographic areas.  Indicated TOs acknowledge, however, that implementing such \nlimitations would require the development of further details and guidelines.965 \n Joint Co-Location Developers argue that PJM and Market Monitor ignore the \ndistinction between simple withdrawal-limiting protection systems that are required by \nPJM for sites taking non-firm transmission service and standard remedial action \nschemes.966  Joint Co-Location Developers explain that unlike standard remedial action \nschemes, which monitor and control components across the grid, simple                      \nwithdrawal-limiting protection systems monitor and control only facility-internal \ncomponents, monitoring flows, adjusting consumption or generation at the site level, and \ndisconnecting from the grid if necessary.  Joint Co-Location Developers argue that \nsimple withdrawal-limiting protection systems can be relied upon much more extensively \nthan standard remedial action schemes without creating the same complexities and \ninterdependencies.  \n \n963 Indicated TOs Reply Brief at 11-13. \n964 Id. at 13-14. \n965 Id. at 14. \n966 Joint Co-Location Developers Reply Brief at 6-7."},{"page":213,"startToken":82773,"endToken":83098,"text":"Docket No. EL25-49-002, et al. \n- 213 - \n Joint Co-Location Developers agree with Indicated TOs that all special protection \nschemes and remedial action schemes should be fully redundant.967 \n Constellation argues that Indicated TOs’ recommendation that PJM impose \nnecessary control technologies and protection systems on both the customer’s side and \nthe transmission owner’s side of the Point of Interconnection for Co-Located Loads as a \ndefault requirement is unsupported and unduly discriminatory.968  Constellation asserts \nthat always requiring double special protection schemes is not good utility practice and \nwould likely be appropriate only in rare situations.969 \n Constellation contends that system studies of unauthorized use should be \nstandardized, transparent, and based on reasonable assumptions set ahead of time to avoid \ndisparate treatment.970  Constellation states that PJM can use the standardized study \nprocesses and established reliability tests in its existing generator interconnection process \nand RTEP process to determine whether a special protection scheme is needed.  \n Constellation argues that criteria for special protection schemes should leverage \ncurrent RTEP planning criteria to develop specific criteria for Co-Located Load risks that \nare reasonable and transparent.971 \n Constellation asserts that the special protection scheme that PJM requires an \nEligible Customer to implement should be commensurate with the risks identified in the \nstudies.  Constellation argues that special protection schemes are not appropriate for \nevery situation, and PJM only requires them when studies identify actual overloads and \nconditions that could cause cascading failures that PJM cannot mitigate through normal \noperations.972  Constellation contends that double special protection schemes should not \nbe employed when other measures can maintain system reliability and real-time \nmonitoring can address any unexpected reliability issue.973 \n \n967 Id. at 7 n.23 (citing Indicated TOs Initial Brief at 23).  \n968 Constellation Reply Brief at 13-14 (citing Indicated TOs Response Brief at 8). \n969 Id. at 14 (citing Kormos Aff. ¶¶ 7, 11). \n970 Id. at 15. \n971 Id. at 15-16. \n972 Id. at 16 (citing Kormos Aff. ¶¶ 5-6). \n973 Id. at 18."},{"page":214,"startToken":83098,"endToken":83465,"text":"Docket No. EL25-49-002, et al. \n- 214 - \n4. \nAnswer \n In response to Constellation, Indicated TOs argue that, in order for an Eligible \nCustomer to take one of the new transmission services, it is necessary and just and \nreasonable to require an Eligible Customer to include appropriate protection systems.974  \nIndicated TOs further assert that special protection schemes on the Co-Located Load \ncustomer’s and the transmission owner’s side of the point of interconnection should not \nbe limited to what Constellation claims are higher-risk situations.975  Indicated TOs claim \nthat, without protection system redundancy, the transmission system is at risk.976  \nIndicated TOs reject Constellation’s assertion that PJM should use a PJM-driven study \nprocess to evaluate special protection schemes, arguing that special protection schemes \nand remedial action schemes are within the purview of the transmission owners, and PJM \nis not equipped to perform these studies.  Indicated TOs also allege that the cost to \nimplement protection systems is extremely low compared to other costs to develop and \ninterconnect Co-Located Load and would not be a deterrent.977 \n5. \nDetermination \n We decline to direct PJM’s proposal as part of the replacement rate because it does \nnot require Eligible Customers taking FCD transmission service to have necessary \ncontrol technologies and/or protection systems to limit their energy withdrawals from the \ntransmission system to their contract demand level.  We find that PJM’s proposal is \ninconsistent with the directives in the December Order.  In the December Order, the \nCommission found that an Eligible Customer that is willing and able to limit its energy \nwithdrawals from the transmission system under certain conditions should be able to take \ntransmission services on behalf of Co-Located Load that reflect their ability to limit \nwithdrawals.978  The Commission stated that where a Co-Location Arrangement includes \nspecial protection schemes that limit its energy withdrawals, it is a just and reasonable \nreplacement rate to allow an Eligible Customer taking transmission service on behalf of \nsuch load to take these transmission services.979  We clarify, however, that the December \n \n974 Indicated TOs May 28 Answer at 4. \n975 Id. at 5. \n976 Id. at 6. \n977 Id. at 7. \n978 December Order, 193 FERC ¶ 61,217 at PP 159-160. \n979 Id. PP 204-205."},{"page":215,"startToken":83465,"endToken":83919,"text":"Docket No. EL25-49-002, et al. \n- 215 - \nOrder did not limit eligibility to take the new transmission services only to Co-Location \nArrangements that include a special protection scheme.980  \n Based on the record here, we find it just and reasonable that, in order for an \nEligible Customer to take Interim NITS, FCD, and/or NFCD transmission services on \nbehalf of any Eligible Load, an Eligible Customer must have necessary control \ntechnologies and/or protection systems, which may include a special protection scheme, \nto limit its energy withdrawals to its contract demand level.981  This replacement rate is \nconsistent with prior Commission precedent for interconnection service, which \nrecognizes that these necessary control technologies and/or protection systems are \nessential to enforce physical limits and ensure system reliability where an Interconnection \nCustomer has requested a level of service below its maximum capacity.982  Further, \nconsistent with the Commission’s determination in Order No. 845, nothing prevents an \nEligible Customer taking Interim NITS, FCD, and/or NFCD transmission service on \nbehalf of Eligible Load from proposing its own necessary control technologies and/or \nprotection systems for consideration, which may include a special protection scheme.983  \n PJM’s proposal falls short because it does not require Eligible Customers taking \nFCD transmission service to have necessary control technologies and/or protection \nsystems to limit their energy withdrawals from the transmission system to their contract \ndemand level.  As such, PJM would have to rely on penalties that disqualify an Eligible \nCustomer from taking FCD transmission service if the Eligible Customer fails to follow \nestablished load shedding and curtailment procedures, and financial penalties for \nunreserved use of the PJM transmission system, to discourage excess energy \nwithdrawals.  However, load shedding and curtailment events for a transmission service \nthat will be treated as the equivalent of NITS for purposes of curtailment will be rare; and \nPJM itself has stated concerns that financial penalties alone are insufficient to deter \n \n980 Id. P 205 (“For these reasons, in these instances where the Co-Location \nArrangement includes special protection schemes that limit its energy withdrawals, we \nfind that it is a just and reasonable replacement rate to allow an Eligible Customer taking \ntransmission service on behalf of such load to take and be charged for new types of \ntransmission service that are alternatives, and not equivalent, to NITS.”). \n981 While we will continue to use the term “special protection scheme” in this \nproceeding, we reiterate that this term is equivalent to “remedial action scheme.”  Id. \nP 204. \n982 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, \n163 FERC ¶ 61,043, at P 367 (2018), order on reh’g, Order No. 845-A, 166 FERC                    \n¶ 61,137, order on reh’g, Order No. 845-B, 168 FERC ¶ 61,092 (2019). \n983 Id. P 372."},{"page":216,"startToken":83919,"endToken":84398,"text":"Docket No. EL25-49-002, et al. \n- 216 - \nunreserved use.984  Accordingly, and consistent with our determination above to extend \nthe three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions, we \ndirect PJM to file, within 60 days of the date of issuance of this order, a compliance filing \nwith Tariff revisions that require Eligible Customers taking Interim NITS, FCD, and/or \nNFCD transmission service on behalf of Eligible Loads, to have necessary control \ntechnologies and/or protection systems.  \n We find it just and reasonable for PJM to include the interconnection requirements \nand operational practices needed for necessary control technologies and/or protection \nsystems in the PJM manuals and, as applicable, to rely on relevant NERC reliability \nstandards, consistent with PJM’s current practices.  Further, we find it appropriate for \nPJM to develop new interconnection requirements and operational practices that \nrecognize the unique nature of Co-Location Arrangements and the new transmission \nservices.  However, PJM has not, to date, actually proposed any interconnection \nrequirements and operational practices specific to Co-Location Arrangements, nor does \nPJM indicate which of its existing interconnection requirements and operational practices \nit will apply to Co-Location Arrangements.  Consistent with our determination above to \nextend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions, we \ndirect PJM to submit, as part of its compliance filing due within 60 days of the date of \nissuance of this order, an explanation of what new and existing interconnection \nrequirements and operational practices it will apply to Eligible Customers taking Interim \nNITS, FCD, and/or NFCD transmission services on behalf of Eligible Load.  We agree \nwith Indicated TOs that it is important for PJM to work with the transmission owners to \ndevelop specificity regarding the requirements associated with necessary control \ntechnologies and/or protection systems necessary to ensure that Eligible Customers do \nnot withdraw energy from the transmission system in excess of their contract demand. \n We do not agree that all parties’ recommendations to clarify PJM’s proposal are \njust and reasonable, or even within the scope of this proceeding.  However, we agree that \nsome guidance on the study and implementation of necessary control technologies and/or \nprotection systems would be of value.  Therefore, and consistent with our determination \nabove to extend the three new transmission services set forth in the December Order to \nEligible Customers taking service on behalf of load with BTMG that are willing and able \nto limit their energy withdrawals from the transmission system under certain conditions, \nwe explain several principles that PJM’s compliance filing should consider. \n \n984 PJM Initial Brief at 50."},{"page":217,"startToken":84398,"endToken":84845,"text":"Docket No. EL25-49-002, et al. \n- 217 - \n First, Eligible Customers shall pay for PJM and transmission owner-administered \nstudies to evaluate and design necessary control technologies and/or protection systems, \nconsistent with their responsibilities for the costs of other studies performed as part of the \nevaluation of their transmission service request.  However, the scope of these studies \nshould be defined in the Tariff, consistent with the level of detail for other transmission \nservices, as discussed in Part VI.A.3.985  Furthermore, we reiterate our finding above that \nan Eligible Customer taking transmission service on behalf of an Eligible Load may \npropose its own necessary control technologies and/or protection systems for \nconsideration as part of this study, which may include a special protection scheme, \nalthough PJM and the transmission owners retain their existing discretion regarding the \ndetermination of what is necessary to ensure the reliability of the transmission system. \n Second, if a special protection scheme is employed as necessary control \ntechnologies and/or protection systems, then such special protection schemes \nimplemented must be, at minimum, fully redundant.  Given questions by commenters \nregarding what “redundant” specifically means, we clarify that such special protection \nschemes must be able to withstand removal of part or all of one scheme due to a failure, \nor to allow for maintenance on a scheme, while providing full scheme capability with a \nfunctionally equivalent and separate scheme.986 \n Third, all necessary control technologies and/or protection systems, which may \ninclude a special protection scheme, must fully meet PJM and transmission owner \ntechnical criteria, as well as any applicable NERC reliability standards. \n Fourth and finally, both PJM and the transmission owners shall have the option to \nreview and agree to the implementation of the Eligible Customer’s necessary control \ntechnologies and/or protection systems as defined in the service agreement, to ensure that \nit meets both PJM and transmission owner technical criteria, and is capable of limiting \nwithdrawals from the transmission system. \n We disagree with Indicated TOs that PJM should include language in the Tariff \nmaking clear that necessary control technologies and/or protection systems may be \nrequired on both the Interconnection Customer’s and the transmission owner’s side of the \nPoint of Interconnection.  PJM and the transmission owners will, as noted in the \nprinciples above, be responsible for evaluating and designing necessary control \ntechnologies and/or protection systems for each Co-Location Arrangement.  The location \nor number of devices required should be based on the engineering judgment of PJM and \n \n985 See supra Part VI.A.3. \n986 See, e.g., WECC, Remedial Action Scheme Design Guide, § 4.10 (July 2022), \nhttps://www.wecc.org/sites/default/files/documents/meeting/2024/WECC%20RAS%20D\nesign%20Guide%202022.pdf."},{"page":218,"startToken":84845,"endToken":85259,"text":"Docket No. EL25-49-002, et al. \n- 218 - \nthe transmission owners.987  Similarly, we find that questions of ownership of these \nfacilities, or the potential to earn a rate of return on said facilities, are outside the scope of \nthis proceeding.  \n In response to Indicated TOs, we find that there is insufficient information in this \nrecord to justify allowing them or PJM to implement and enforce limits on the total \namount of load that can be covered by a special protection scheme.  If PJM or its \ntransmission owners wish to impose a specific limit, they may submit a new filing under \nFPA section 205 with a sufficient showing, based on experience gained once Eligible \nCustomers begin taking Interim NITS, FCD, and/or NFCD transmission service on behalf \nof Eligible Load.  However, implementation of a special protection scheme should not be \nuniversally required as a condition of taking these transmission services; rather, only \nnecessary control technologies and/or protection systems are required.  If PJM or its \ntransmission owners wish to limit the use of special protection schemes on their system, \nthey can also design necessary control technologies and/or protection systems for Eligible \nCustomers that do not have a special protection scheme. \n We decline to address NOVEC’s request that the Commission direct NERC to \nestablish registration requirements for Co-Located Loads.  Whereas NOVEC’s request \nmay be availing in the context of a FPA section 215 proceeding, the instant case arises \nunder FPA section 206.  In addition, NERC is already considering registration \nrequirements for large loads, including potentially Co-Located Loads, as part of its Large \nLoad Action Plan.988 \nD. \nPenalty Charge or Other Remedial Action for New Transmission \nServices \n1. \nInitial Briefs \n PJM proposes different penalties where an Eligible Customer:  (1) fails to follow \nestablished load shedding and curtailment procedures; (2) relies on necessary control \n \n987 Cf. RWE Clean Energy, LLC v. PJM Interconnection, L.L.C., 194 FERC \n¶ 61,212, at P 42 (2026) (“The Commission generally allows transmission providers to \nexercise their engineering judgment when conducting interconnection studies, including \ndeferring to transmission providers’ discretion regarding how to maintain a reliable \ntransmission system.”); Order No. 1920-A, 189 FERC ¶ 61,126 at P 450 (“Finally, we \nclarify that the Commission generally provides transmission providers with the discretion \nto use engineering judgment in designing and conducting transmission planning studies, \nand we therefore decline to address Dominion’s hypothetical in the abstract.”). \n988 See NERC, Large Loads Action Plan, https://www.nerc.com/initiatives/large-\nloads-action-plan (last visited May 15, 2026)."},{"page":219,"startToken":85259,"endToken":85696,"text":"Docket No. EL25-49-002, et al. \n- 219 - \ntechnologies or protection systems that fail more than once; and (3) makes unreserved \nuse of the transmission system.989  PJM argues that, where an Eligible Customer fails \nonce to respond to established load shedding and curtailment procedures, the customer is \ndisqualified automatically because of the significant reliability risk.  PJM asserts that its \nproposal is just and reasonable and consistent with the key principles that (1) Eligible \nCustomers are willing and able to control their withdrawals from the transmission system \nand (2) the services are designed to allow PJM to maintain system reliability.  PJM \nproposes that, if the Eligible Customer is taking FCD or NFCD transmission service and \nis disqualified, such customer may still take NITS or Interim NITS.  PJM proposes that, if \nthe Eligible Customer is taking Interim NITS and is disqualified, such customer may take \nNITS.990 \n PJM argues that when a control technology or protection scheme misoperates \nthere can be serious consequences.991  PJM proposes that, after one instance of \nmisoperation, the Eligible Customer will be prohibited from taking transmission service \nor otherwise withdrawing energy from the transmission system for a period of up to               \n120 days from misoperation to allow for an analysis of the necessary control technology \nor protection system scheme’s operational performance.  PJM asserts that this proposed \npause is consistent with NERC requirements for an investigation into the operation of a \nremedial action scheme992 and will allow PJM time to investigate, identify, and \nimplement fixes to better protect the transmission system.993  PJM proposes that, after \ntwo instances of misoperation, the Eligible Customer will be automatically disqualified \nfrom taking the relevant new transmission service because of the significant reliability \nrisks.  PJM asserts that this rule properly balances the need to protect reliability against \nthe desire of an Eligible Customer taking service on behalf of a Co-Located Loads to take \na transmission service lesser than NITS because the Co-Located Loads  are willing and \nable to limit their energy withdrawals.  PJM maintains that a second instance of a \nmisoperation makes it evident that the necessary control technology or protection system \ncannot adequately protect the system from the Co-Located Load’s unreserved energy \nwithdrawals.  PJM explains that an Eligible Customer disqualified from taking FCD or \n \n989 PJM Initial Brief at 40. \n990 Id. at 41-43. \n991 Id. at 43-44.  Misoperation, as contemplated by PJM, relies on and incorporates \nthe term as defined by NERC (e.g., PRC-004-6).  See, e.g., NERC, PRC-004-6 – \nProtection System Misoperation Identification & Correction (June 12, 2025), \nhttps://www.nerc.com/globalassets/standards/reliability-standards/prc/prc-004-6.pdf. \n992 Reliability Standard PRC-004-6. \n993 PJM Initial Brief at 45."},{"page":220,"startToken":85696,"endToken":86029,"text":"Docket No. EL25-49-002, et al. \n- 220 - \nNFCD transmission service on this ground may either take NITS or Interim NITS, and \nthat an Eligible Customer disqualified from taking Interim NITS on this ground may take \nNITS.  PJM supports its proposal to permit an Eligible Customer disqualified from taking \nthe new transmission services to take NITS by reasoning that NITS, in and of itself, \naddresses curtailment, load shed, and control technology or protection scheme \nmisoperation risk.994  \n PJM states that it supports a penalty for unreserved use in addition to the \noperational penalties and intends to work with the transmission owners to explore a \nfinancial penalty.995  PJM argues that financial penalties alone are insufficient to \nincentivize Eligible Customers to comply with load shed, curtailment, and control \ntechnology and protection system obligations.  PJM asserts that many, if not most, \nEligible Customers taking service on behalf of a Co-Located Load could elect to absorb \nfinancial penalties for unreserved use rather than follow curtailment or load shed \nprocedures or avoid misoperation of the protective technology or system. \n Indicated TOs assert that any penalty regime should rely on both operational \nconsequences and complementary financial penalties.996  Indicated TOs allege that it is of \nthe utmost importance that Co-Located Loads respect contractual limits because                \nCo-Location Arrangements involve substantial amounts of load connected to the grid and \nfailure to respect these limits could pose severe reliability consequences for the system.   \n Indicated TOs support PJM’s proposal but argue that additional details must be \ndeveloped as to how operational consequences would be applied.997  Indicated TOs also \nstate that financial penalties could be valuable where the Eligible Customer exceeds its \ncontract demand, even if such deviations are mitigated by a special protection scheme. \n2. \nResponse Briefs \n ODEC supports PJM’s proposed penalty structure, including operational \npenalties.998  NOVEC states that disqualification for failure to follow load shedding or \n \n994 Id. at 45-50. \n995 Id. at 50. \n996 Indicated TOs Initial Brief at 19. \n997 Id. at 20. \n998 ODEC Response Brief at 11."},{"page":221,"startToken":86029,"endToken":86418,"text":"Docket No. EL25-49-002, et al. \n- 221 - \ncurtailment procedures is necessary to protect the integrity of the transmission system.999  \nIndicated TOs request that Tariff language be included requiring that the relevant \ntransmission owner’s approval be obtained before service to an Eligible Customer is \nreinstated following a control technology/protection system misoperation. \n Constellation opposes the proposal to suspend or disqualify an Eligible Customer, \narguing it is excessive and applies regardless of fault and does not apply to Non-Firm \nPTPS customers.1000  Constellation urges the Commission to follow SPP’s proposal for \nConditional High Impact Large Load Service (CHILLS) and align treatment of \nunreserved use for the new services with its treatment of Non-Firm PTPS.  DCC \nexpresses concern about PJM’s operational penalties in light of the lack of clarity around \nPJM’s curtailment procedures for the new transmission services.1001  Vistra similarly \nargues that PJM’s proposed operational penalties diverge from the Commission’s \ndirectives and violate the comparability principle because the December Order does not \ncontemplate disqualification and, more generally, such a penalty structure exceeds what \nthe Commission has allowed for unreserved use of the transmission system.1002  Vistra \ncontends that PJM’s proposal is excessively punitive and may be unduly discriminatory \nin comparison to customers that take PTPS.  Vistra also alleges that PJM’s proposal also \nviolates the comparability requirement because it treats Co-Location Arrangements using \nspecial protection schemes differently from any other entities using such schemes.  Vistra \nalso points out that, if the Commission accepts transmission owners’ proposal to own \nspecial protection schemes, then misoperation of such schemes must attach to the \ntransmission owner, not the Eligible Customer.  \n Joint Co-Location Developers argue that PJM’s proposed penalty provisions are \nunjust and unreasonable because they are not “narrowly designed to balance the need to \ndeter conduct that is harmful to the system with the need to limit excessive and \nunnecessary costs.”1003  Joint Co-Location Developers express concern that PJM’s \nproposed disqualification rules will dissuade Eligible Customers from taking the new \ntransmission services because of the risk of stranding or undermining investments in the \n \n999 NOVEC Response Brief at 11-12. \n1000 Constellation Response Brief at 19-20.  See also Joint Co-Location Developers \nResponse Brief at 25. \n1001 DCC Response Brief at 7. \n1002 Vistra Response Brief at 29-31. \n1003 Joint Co-Location Developers Response Brief at 23 (quoting Mirant Kendall, \nLLC, 110 FERC ¶ 61,272, at P 17 (2005))."},{"page":222,"startToken":86418,"endToken":86826,"text":"Docket No. EL25-49-002, et al. \n- 222 - \nnew services.1004  Joint Co-Location Developers propose that PJM adopt financial \npenalties sufficient to deter gaming of transmission service subscription.  Joint                 \nCo-Location Developers contend that a disqualification-based penalty is not necessary \nbecause transmission owners can manually disconnect a facility in case of potential \nsevere reliability risk.  Joint Co-Location Developers assert that failure to respond to \ncurtailment would have a similar impact from a resource adequacy perspective to a \ncapacity resource failing to perform during emergency events, in which case only a                \nnon-performance charge is assessed.  Joint Co-Location Developers urge that, if the \nCommission adopts disqualification as a penalty, the Commission should adopt intent (or \nat least fault), materiality, and repetition elements prior to disqualification to ensure \ndisqualification sends an actionable signal.1005  Joint Co-Location Developers suggest \nthat that an operational penalty is excessive for misoperation of control technologies or \nprotection systems because misoperation without withdrawal does not risk system \nharm.1006 \n Indicated TOs propose a financial penalty charge structure with two components:  \n(1) a base penalty charge; and (2) a penalty ratchet.1007  The base penalty charge would be \nassessed for any hour in which at least one five-minute interval occurs during which a \ncustomer’s metered load at the Point of Interconnection exceeds its reserved transmission \nservice.  The penalty ratchet would apply additional daily penalties if exceedances \noccurred in more than one hour during a day, additional weekly penalties if exceedances \noccurred on more than one day during a week, and additional monthly penalties if \nexceedances occurred in more than one week during a month.  Further, each of these \npenalties would entail escalating financial liabilities for repeated penalties, which \nIndicated TOs argue would reinforce the expectation that Co-Located Load customers \nmanage their load in a manner consistent with their reserved transmission service.  \n NOVEC states that a penalty for unreserved use in addition to disqualification and \npause-in-service rules is appropriate, as this penalty would be an additional deterrent that \nwould help make the market or other ratepayer whole if a Co-Located Load customer \nexceeds its contract demand.1008  NOVEC suggests that any financial penalty should \ncompensate other customers for any harm caused by the Eligible Customer’s departure \n \n1004 Id. at 24-25. \n1005 Id. at 26 (citing PJM Interconnection, L.L.C., 178 FERC ¶ 61,104, at PP 60-61 \n(2022)). \n1006 Id. at 26. \n1007 Indicated TOs Response Brief at 12-13. \n1008 NOVEC Response Brief at 13 (citing Indicated TOs Initial Brief at 20)."},{"page":223,"startToken":86826,"endToken":87251,"text":"Docket No. EL25-49-002, et al. \n- 223 - \nfrom Co-Location requirements or, if there is no harm, be set at a level sufficient to \nencourage compliance with the Tariff’s scheduling requirements. \n ODEC suggests that the Commission also consider whether any protections are \nneeded for local utilities or transmission owners should they need to take the \nextraordinary measure of disconnecting an Eligible Customer taking service on behalf of \nCo-Located Loads, if the Eligible Customer’s use of the transmission system exceeds \ncontract demand or is called upon for load shedding and curtailment.1009  ODEC states \nthat, in such instance, the local utility or transmission owner should not be liable for \nlegal, financial, or other damages that might be experienced by an Eligible Customer.  \nNOVEC asserts that PJM’s penalty language should be revised to specify that when an \nEligible Customer serves multiple Co‑Located Loads, only the culpable Co‑Located Load \nis disqualified rather than the Eligible Customer as a whole.1010 \n3. \nReply Briefs \n PJM argues that monetary penalties, in place of non-monetary penalties, would \nundermine the value of reliability and hand it to a single site or a class of load that may \ndecide to pay the penalty in place of operating as agreed to ensuring overall system \nreliability.1011  PJM alleges that non-monetary operational penalties are essential to the \nresponsible integration of large loads.  PJM maintains that its non-monetary operational \npenalties represent a measured approach that balances significant reliability concerns \nwith the interest in integrating large loads quickly.  However, PJM notes that, in response \nto protesters’ concerns, PJM proposes revisions to its illustrative tariff language to add \ndiscretion to the strict application of non-monetary operational penalties.   \n PJM argues that the Commission did not foreclose non-monetary penalties \nbecause the December Order “also direct[s] parties to brief . . . any other remedial action \nthat PJM should take to address withdrawals in excess of the contract demand.”1012  PJM \nalso claims that financial penalties alone are insufficient to support reliability in light of \nthe volume of load that is anticipated to come online in short order and the nature of how \nthese new loads will seek to connect through co-location with potentially critical \ngenerators.  PJM rejects Vistra’s contention that non-monetary penalties are a departure \nfrom Commission precedent, and responds that the Commission has long held that where \nmonetary penalties do not incentivize actions consistent with reliability, it may be \n \n1009 ODEC Response Brief at 11-12. \n1010 NOVEC Response Brief at 14-15. \n1011 PJM Reply Brief at 40-43.  \n1012 Id. at 49-50 (quoting December Order, 193 FERC ¶ 61,217 at P 212)."},{"page":224,"startToken":87251,"endToken":87668,"text":"Docket No. EL25-49-002, et al. \n- 224 - \nnecessary to implement “a range of non-monetary and monetary penalties” to promote \nbehavior that supports and improves the reliability of the bulk power system.1013  PJM \nrejects Joint Co-Location Developers’ suggestion that PJM adopt financial penalties \nsufficient to deter gaming, and responds that PJM’s proposed penalty structure is not \nintended to address gaming but to support reliability.  In response to Joint Co-Location \nDevelopers’ suggestion that disqualification is unnecessary because transmission owners \ncan manually disconnect a facility, PJM argues that it is inconsistent with reliable \noperation of the transmission system to shift responsibility away from the Eligible \nCustomer.  PJM also alleges that it and the transmission owner will become aware of an \nimproperly set-up protection scheme only after the misoperation incident, which will \nexpose the PJM system to risk.  PJM adds that when a transmission owner manually cuts \nload suddenly, without proper coordination, it can have disastrous and dangerous \ncascading system effects.1014 \n Nevertheless, PJM proposes revisions to its illustrative tariff language to permit, \nwhere appropriate, PJM to exercise discretion in determining when disqualification \npenalties are appropriate based on PJM’s assessment of factors including the reliability \nimpact of the failure to curtail or shed load or the misoperation of control technologies or \nprotection system schemes.  PJM adds that, with these revisions, the Eligible Customer \ntaking transmission service on behalf of Co-Located Load will not be held liable for the \nactions of others.1015 \n Several parties agree that financial penalties are insufficient to ensure \nreliability.1016  ODEC asserts that it does not agree that PJM’s proposed suspension and \ndisqualification measures are unfairly imposed regardless of fault and will make the \nservices unduly risky for many loads.  Earthjustice argues that PJM’s operational \npenalties are proportionate to the prospective harm associated with a customer’s failure to \nfollow curtailment orders.  Earthjustice argues that, while opposing commenters note that \nPJM’s proposed penalties are stricter than the penalties it has levied in other \ncircumstances, those comments fail to acknowledge that the stakes here are higher.  \n \n1013 Id. at 51 (quoting Rules Concerning Certification of the Elec. Reliability Org.; \nand Procs. for the Establishment, Approval, and Enf’t of Elec. Reliability Standards, \nOrder No. 672, 114 FERC ¶ 61,104, at PP 49, 455, order on reh’g, Order No. 672-A,            \n114 FERC ¶ 61,328 (2006)). \n1014 Id. at 52-53. \n1015 Id. at 54. \n1016 ODEC Reply Brief at 4-5; Earthjustice Reply Brief at 2-3, 5, 8; Indicated TOs \nReply Brief at 14-15 (citing Joint Blazunas/Schafer/Hammer Rebuttal Test. at 4)."},{"page":225,"startToken":87668,"endToken":88053,"text":"Docket No. EL25-49-002, et al. \n- 225 - \nEarthjustice argues that PJM’s penalty proposal is appropriately designed to protect \nsystem reliability, rather than assign fault.   \n Industrials/Amtrak urge the Commission to exercise caution in overly harsh \noperational penalties, especially for existing retail customers who may be forced to move \nfrom retail BTMG arrangements to Co-Location Arrangements.  Industrials/Amtrak \nargue that it is reasonable to pay financial penalties, but a retail customer should not be \nbanned from NFCD transmission service for a lone violation.1017 \n PJM rejects Vistra’s contention that its non-monetary penalties for misoperation of \nnecessary control technologies or protection systems are unduly discriminatory.  PJM \nalleges that NERC, Market Monitor, and PJM’s 2026 load forecast each demonstrate that \nthe new large loads integrating into PJM’s transmission system are not similarly situated \nto traditional loads.  PJM adds that disqualification penalties do not foreclose Eligible \nCustomers from taking transmission service entirely, and that, where Eligible Customers \ndemonstrate that they cannot (or are unwilling to) limit withdrawals, it is appropriate for \nthose Eligible Customers to take NITS.1018 \n Indicated TOs reject Constellation’s argument that PJM should simply adopt \nfinancial penalties as is the case with SPP’s High Impact Large Load (HILL) process.1019  \nIndicated TOs argue that SPP’s HILL process is different in that, under PJM’s proposal, \nCo-Located Load customers may be in the position of installing and operating their own \ncontrol technologies and protection systems.  Indicated TOs further argue that PJM and \nSPP are different regions with different characteristics, including topology and \nproliferation of large loads.  Indicated TOs also dismiss DCC’s and Vistra’s concerns \nregarding Co-Located Load’s liability for penalties associated with control technologies \nand protection systems operated by other parties, including transmission owners.  \nIndicated TOs argue that installation of redundant protection facilities by transmission \nowners should not serve as an excuse for the failure of customers to properly maintain \nand operate their own equipment.  \n NOVEC states that it generally supports Indicated TOs’ proposed financial penalty \ncharge structure, subject to Indicated TOs providing further information.1020  ODEC \nsupports financial penalties but states that PJM’s implementation of its penalties must not \nsubject ODEC or its member distribution cooperatives to service interruptions or \n \n1017 Industrials/Amtrak Reply Brief at 17-18. \n1018 PJM Reply Brief at 43, 45, 47. \n1019 Indicated TOs Reply Brief at 15-16. \n1020 NOVEC Reply Brief at 26-27."},{"page":226,"startToken":88053,"endToken":88435,"text":"Docket No. EL25-49-002, et al. \n- 226 - \ndisqualification, or financial penalties, as a result of requiring ODEC to serve as the \nEligible Customer.1021 \n Indicated TOs further explain their financial penalty proposal, explaining that \nwhen a Co-Located Load exceeds its reserved transmission service limit, which includes \nany reductions based on curtailments directed by PJM, the base penalty charge will be \nassessed for any hour (Exceedance Hour) in which at least one five-minute interval \n(Exceedance Interval) occurs during which a customer’s metered load at the point of \ndelivery exceeds its reserved transmission service.  Indicated TOs state that the base \npenalty charge will apply to each Exceedance Hour.1022 \n Indicated TOs state that the base penalty charge will be calculated as the product \nof the Hourly Exceedance MW, the Equivalent Hourly FCD transmission service rate, \nand the number of Exceedance Intervals within the hour, where the Hourly Exceedance \nMW is equal to the maximum telemetered load during the hour less the reserved \ntransmission service limit for the hour and where the Equivalent Hourly FCD \ntransmission service rate is equal to the FCD transmission service rate divided by                \n8,760 hours.1023  Indicated TOs explain that the FCD transmission service rate is used as \nthe basis for assessing the penalty because, when a customer exceeds its reserved \ntransmission service limit without authorization, the excess usage effectively imposes \nfirm-level demand on the system.   \n Indicated TOs state that the penalty ratchet applies escalating FCD-equivalent \ntransmission service rates as the frequency of unreserved transmission use increases.  \nIndicated TOs explain that the penalty ratchet applies daily, weekly, monthly, or annual \npenalty charges depending on whether exceedances occur within the same calendar day, \nweek, month, or year, and that these penalty charges are equal to the Daily                         \nFCD-Equivalent Rate, Weekly FCD-Equivalent Rate, Monthly FCD-Equivalent Rate, \nand FCD Annual Rate, respectively.1024  Indicated TOs further explain that, where a daily \npenalty charge is assessed, it is in addition to the base penalty charge applicable to each \nindividual Exceedance Hour; where a weekly penalty charge is assessed, it is in addition \nto the base penalty charges and daily penalty charges; and so on.   \n \n1021 ODEC Reply Brief at 4. \n1022 Indicated TOs Reply Brief at 16-17. \n1023 Indicated TOs Reply Brief, Joint Blazunas/Schafer/Hammer Rebuttal Test. \nat 8-9. \n1024 Id. at 10-14."},{"page":227,"startToken":88435,"endToken":88821,"text":"Docket No. EL25-49-002, et al. \n- 227 - \n Indicated TOs propose to distribute daily, weekly, and monthly penalty revenues \non a monthly basis to Eligible Customers taking NITS or FCD transmission service that \nhave not been penalized during the month, as pro rata bill credits.  Indicated TOs further \npropose to distribute annual penalty charges on an annual basis to Eligible Customers \ntaking NITS and FCD transmission service that have not been penalized during the year \nas pro rata bill credits.1025 \n4. \nAnswer \n Constellation alleges that PJM’s reliability arguments are not persuasive, because \nPJM’s example involves grid-connected load, not Co-Located Load.1026  Constellation \nargues that PJM fails to explain how resource adequacy concerns justify its proposed \npenalty scheme, and points out that PJM has proposed no such penalties for Connect and \nManage.1027  Constellation next argues that a four-month suspension is not consistent \nwith NERC requirements, as PJM claims.1028 \n5. \nDetermination \n We find that it is just and reasonable to impose operational and financial penalties \non Eligible Customers taking the three new transmission services as part of the \nreplacement rate, given that these services are designed for Eligible Customers taking \ntransmission service on behalf of Eligible Loads that are willing and able to limit their \nwithdrawals from the transmission system under certain conditions, and there are \nsignificant reliability risks if Eligible Customers fail to do so.  However, we decline to \nadopt PJM’s proposed replacement rate.  First, we disagree that it is just and reasonable \nto disqualify an Eligible Customer from taking any of the new transmission services after \nthe first instance of failing to follow a curtailment or load shedding directive, as \ndiscussed below.  We instead find that it is just and reasonable to establish an operational \npenalty whereby, after the second instance of failing to follow a curtailment or load \nshedding directive, PJM will terminate the transmission service agreement with the \nEligible Customer taking Interim NITS, FCD, or NFCD transmission service on behalf of \nthe Eligible Load.  We agree with PJM that there are significant reliability risks \nassociated with failing to follow a curtailment or load shedding directive, but we find that \nPJM’s one strike proposal is unnecessarily strict.  We direct PJM to file, within 60 days \n \n1025 Id. at 15-16. \n1026 Constellation May 11 Answer at 8-9. \n1027 Id. at 9. \n1028 Id. at 9-10."},{"page":228,"startToken":88821,"endToken":89281,"text":"Docket No. EL25-49-002, et al. \n- 228 - \nof the date of issuance of this order, a compliance filing to revise its Tariff consistent \nwith these findings.   \n Second, we find that it is just and reasonable to establish an operational penalty of \nsuspension in service for a period of up to 120 days for an Eligible Customer taking \nInterim NITS, FCD, and/or NFCD transmission service after the first misoperation of \nnecessary control technologies and/or protection systems given the reliability risks \nassociated with such misoperation.  However, as above, we disagree with PJM’s proposal \nregarding disqualification, and we instead find that it is just and reasonable to establish an \noperational penalty whereby, after the second misoperation of necessary control \ntechnologies and/or protection systems, PJM will terminate the transmission service \nagreement with the Eligible Customer taking Interim NITS, FCD, and/or NFCD \ntransmission service on behalf of Eligible Load.  We direct PJM to file, within 60 days of \nthe date of issuance of this order, a compliance filing to revise its Tariff consistent with \nthese findings.   \n Third, we find that it is just and reasonable to subject an Eligible Customer taking \nany of the three new transmission services on behalf of Eligible Load to financial \npenalties in any circumstance where the transmission customer uses transmission service \nthat it has not reserved.  We thus direct the PJM transmission owners to file, within             \n60 days of the date of issuance of this order, a compliance filing that effectuates Indicated \nTOs’ proposed framework for financial penalties for Eligible Customers taking one of the \nthree new transmission services that withdraw from the transmission system in excess of \ntheir contract demand level (i.e., for unreserved use).  \n Before addressing each topic in turn, as an initial matter, we disagree with \nprotesters that operational penalties, either for failure to follow a curtailment or load \nshedding directive, or for misoperation of necessary control technologies and/or \nprotection systems, “diverg[e] from” or were “not contemplated” in the December \nOrder.1029  The financial penalties that the Commission required only apply to Eligible \nCustomers’ unreserved use of the transmission system and are consistent with the \nCommission’s directives in the December Order.1030  The Commission has previously \nfound that transmission customers should be subject to unreserved use penalties in \ncircumstances where a transmission customer uses transmission service in excess of its \n \n1029 Constellation Response Brief at 19; Vistra Response Brief at 29. \n1030 December Order, 193 FERC ¶ 61,217 at P 212 (directing a penalty rate for \nexcess withdrawals of energy from the transmission system by an Eligible Customer \ntaking FCD transmission service on behalf of a Co-Located Load); id. P 217 (directing \nsame as to excess withdrawals by an Eligible Customer taking NFCD transmission \nservice on behalf of a Co-Located Load)."},{"page":229,"startToken":89281,"endToken":89752,"text":"Docket No. EL25-49-002, et al. \n- 229 - \nreserved capacity or if it uses transmission service where it does not have a reservation, \nand as discussed further below, we find it just and reasonable that an Eligible Customer \ntaking any of the three new transmission services on behalf of Eligible Load incur a \nfinancial penalty for unreserved use of the transmission system.1031  But the Commission \nalso directed briefing broadly on the rates, terms, and conditions of the new transmission \nservices, including “other remedial action[s]” in addition to financial penalties, as \npertinent to this question.1032  We find that an operational penalty for Eligible Customers \ntaking Interim NITS, FCD transmission service, and/or NFCD transmission service on \nbehalf of Eligible Load for misoperation of necessary control technologies and/or \nprotection systems is consistent with the December Order’s finding that Eligible \nCustomers may take Interim NITS, FCD transmission service, and/or NFCD transmission \nservice because it is the use of necessary control technologies and/or protection systems \nthat effectively limits their energy withdrawals from the transmission system.1033  The \nCommission in the December Order also broadly sought briefing on the appropriate \nprocedures to govern circumstances under which PJM curtails an Eligible Customer \ntaking any of the three new transmission services, and we find that an operational penalty \nfor an Eligible Customer taking the new transmission services on behalf of Eligible Load \nfailing to follow a curtailment or load shedding directive is within the scope of provisions \nthat we can consider as part of establishing curtailment procedures for the three new \ntransmission services.      \na. \nFailure to Follow Curtailment or Load Shedding Directive \n We find that it is just and reasonable to establish an operational penalty for an \nEligible Customer taking any of the new transmission services on behalf of Eligible Load \nafter the second instance of failing to follow a curtailment or load shedding directive.  \nSpecifically, we find that it is just and reasonable for PJM to terminate the transmission \nservice agreement with the Eligible Customer taking Interim NITS, FCD transmission \nservice, or NFCD transmission service on behalf of Eligible Load after the second \ninstance of failing to follow a curtailment or load shedding directive.  We direct PJM to \nfile, within 60 days of the date of issuance of this order, a compliance filing to revise its \nTariff consistent with this finding.  PJM persuasively argues that there are significant \nreliability risks associated with failure to curtail, and “financial penalties, alone, are not \nsufficient to incentivize Eligible Customers to comply with Load Shed and \nCurtailment.”1034  However, we agree with concerns raised in the record that PJM’s \n \n1031 Order No. 890, 118 FERC ¶ 61,119 at P 834.  \n1032 December Order, 193 FERC ¶ 61,217 at P 219. \n1033 Id. P 205; see supra Part VI.C. \n1034 PJM Initial Brief at 41-42, 45, 50."},{"page":230,"startToken":89752,"endToken":90232,"text":"Docket No. EL25-49-002, et al. \n- 230 - \nproposal to disqualify an Eligible Customer taking one of the three new transmission \nservices on behalf of Eligible Load from continuing to take any of those services is \nunnecessarily strict.  When considering the need to ensure reliability is preserved, as well \nas to allow Eligible Customers taking transmission service on behalf of Eligible Load to \nadapt to a new transmission service paradigm, we find that, on balance, complete \ndisqualification is excessive because it would impose penalties on the Eligible Customer \nthat apply to all of its transmission service agreements, even those for which it has \nfollowed all curtailment or load shedding directives.  However, we agree with PJM that a \nstrict operational penalty will deter conduct contrary to the fundamental principle upon \nwhich the new transmission services required by the December Order were based, which \nis that Eligible Customers taking service on behalf of Co-Located Loads are willing and \nable to limit their energy withdrawals from the transmission system under certain \nconditions.1035  We therefore find, as part of the just and reasonable replacement rate, that \nthe transmission service agreement with the Eligible Customer taking Interim NITS, FCD \ntransmission service, or NFCD transmission service on behalf of Eligible Load should be \nterminated on the second instance of failing to follow a curtailment or load shedding \ndirective.  The Eligible Customer will remain eligible to take the three new transmission \nservices on behalf of other Eligible Loads through its other transmission service \nagreements.  NITS remains an option for an Eligible Customer disqualified from taking \none of the new transmission services; however, such Eligible Customer may not begin \ntaking NITS until all necessary Network Upgrades are completed.1036 \n Recognizing that we are not adopting the exact penalty framework for failing to \nfollow a curtailment or load shedding directive that PJM proposes, we nevertheless \ndisagree with many of protesters’ arguments on this matter.  Joint Co-Location \nDevelopers, for example, argue that disqualification is not necessary because \ntransmission owners can manually disconnect a facility.  This argument supports PJM’s \npremise that a financial penalty alone cannot deter the Eligible Customer taking one of \nthe three new transmission services on behalf of Co-Located Load from failing to control \nunauthorized withdrawals; instead, it unreasonably and unnecessarily shifts the \nresponsibility to manage complying with the Tariff and the terms of the transmission \nservice from the Eligible Customer to the transmission owners.  Joint Co-Location \n \n1035 December Order, 193 FERC ¶ 61,217 at P 177 (“we also find that PJM’s \nTariff is unjust and unreasonable because it does not include transmission services that \nreflect Eligible Customers taking service on behalf of Co-Located Loads that are willing \nand able to limit their energy withdrawals from the transmission system under certain \nconditions.”). \n1036 See PJM Initial Brief at 43 (“Importantly, however, such an Eligible Customer \nmay take NITS, which would begin after all necessary upgrades are placed into \nservice.”)."},{"page":231,"startToken":90232,"endToken":90571,"text":"Docket No. EL25-49-002, et al. \n- 231 - \nDevelopers also claim that disqualification is disproportionate and may not send an \nactionable signal without “fault or materiality elements.”  This argument is misplaced, as \nPJM’s requirements for the new transmission services make the Eligible Customer’s \nresponsibilities clear and actionable:  prior to commencement of service, the Eligible \nCustomer must demonstrate to PJM’s satisfaction that it can fully comply with load \nshedding and curtailment procedures.  Lastly, Joint Co-Location Developers suggest that \nthe Commission’s approval of a non-performance charge rate for capacity resources that \nfail to perform in emergency events means that an Eligible Customer that fails to follow a \ncurtailment or load shedding directive can be sufficiently penalized through a similar \ncharge.  Joint Co-Location Developers allege that failure to respond or perform in both \nthese circumstances is similar from a resource adequacy perspective.  We disagree that \nthe two are comparable.  Capacity resources are purchased to meet the needs of \ntransmission customers taking existing firm service, such as NITS.  As PJM explains in \nits initial brief, the choice to take NITS decreases the likelihood of significant issues \narising from failure to curtail.1037  By contrast, the Commission created the three new \ntransmission services to reflect that Eligible Customers taking transmission service on \nbehalf of Co-Located Load are willing and able to limit their energy withdrawals from \nthe transmission system under certain conditions that are different than those under which \nNetwork Customers take NITS.1038  For these reasons, we find that it is just and \nreasonable to subject Eligible Customers on behalf of such loads to a stricter penalty \nregime. \n We also disagree with Constellation’s suggestion that the Commission should \nadopt SPP’s approach for CHILLS, which contains only penalties for exceeding the \ntransmission customer’s reserved capacity.1039  The Commission has permitted regional \n \n1037 Id. at 48-49. \n1038 December Order, 193 FERC ¶ 61,217 at P 2; see, e.g., id. P 208 \n(distinguishing an Eligible Customer’s rights under FCD transmission service in contrast \nto NITS). \n1039 Sw. Power Pool, Inc., 195 FERC ¶ 61,196, at 98 (2026)."},{"page":232,"startToken":90571,"endToken":91025,"text":"Docket No. EL25-49-002, et al. \n- 232 - \nvariation among RTOs/ISOs1040 and need only explain its choice and how it has chosen a \njust and reasonable rate.1041   \n We also find that ODEC has not demonstrated a need, nor does the record \ndeveloped in this paper hearing otherwise reflect a need, to establish protections for \ntransmission owners if the Eligible Customer may experience damages as a result of the \ntransmission owner disconnecting the Eligible Customer.  Lastly, with respect to Joint \nCo-Location Developers’ concern that PJM’s proposed disqualification rules will \ndissuade Eligible Customers from taking the new transmission services because of the \nrisk of stranding or undermining investments in the new transmission services, we note \nthat an Eligible Customer is not required to take the new transmission services and may \nelect to take NITS if that transmission service option better reflects the Eligible \nCustomer’s use of the transmission system and risk profile.1042   \n \n1040 See, e.g., Reg’l Transmission Orgs., Order No. 2000, FERC Stats. & Regs.                 \n¶ 31,089, at 31,073 (1999) (cross-referenced at 89 FERC ¶ 61,285), order on reh’g, \nOrder No. 2000-A, FERC Stats. & Regs. ¶ 31,092 (2000) (cross-referenced at 90 FERC  \n¶ 61,201), aff’d sub nom. Pub. Util. Dist. No. 1 of Snohomish Cnty. v. FERC, 272 F.3d \n607 (D.C. Cir. 2001) (stating there is no “one size fits all” approach to RTO governance); \nOffer Caps in Mkts. Operated by Reg’l Transmission Orgs. & Indep. Sys. Operators, \nOrder No. 831, 157 FERC ¶ 61,115, at P 147 (2016), order on reh’g & clarification, \nOrder No. 831-A, 161 FERC ¶ 61,156 (2017) (permitting regional variation for treatment \nof incremental energy offers above $1,000/MWh that the RTO/ISO or Marketing \nMonitoring Unit cannot verify prior to the start of the market clearing process); \nWholesale Competition in Regions with Organized Elec. Mkts., Order No. 719,                        \n125 FERC ¶ 61,071, at P 62 (2008), order on reh’g, Order No. 719-A, 128 FERC                     \n¶ 61,059, order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009) (permitting \nregional variation for RTOs/ISOs developing requirements for demand response \nresources participating in ancillary service markets).   \n1041 See ExxonMobil Oil Corp. v. FERC, 487 F.3d 945, 955 (D.C. Cir. 2007) (“We \nneed not decide whether the Commission has adopted the best possible policy as long as \nthe agency has acted within the scope of its discretion and reasonably explained its \nactions.”); Cities of Batavia v. FERC, 672 F.2d 64, 84 (D.C. Cir. 1982) (“[T]he billing \ndesign need only be reasonable, not theoretically perfect.”). \n1042 See PJM Reply Brief at 47 (arguing that disqualification penalties reflect that \nEligible Customers take the level of transmission service that aligns with their \ndemonstrated use of the transmission system)."},{"page":233,"startToken":91025,"endToken":91496,"text":"Docket No. EL25-49-002, et al. \n- 233 - \nb. \nMisoperation of Necessary Control Technologies and/or \nProtection Systems \n We find that it is just and reasonable to establish an operational penalty of \nsuspension in service for a period of up to 120 days for an Eligible Customer taking \nInterim NITS, FCD, and/or NFCD transmission service on behalf of Eligible Load after \nthe first misoperation of necessary control technologies and/or protection systems.  \nHowever, as noted above, we disagree with PJM’s proposal regarding disqualification, \nand we instead find that it is just and reasonable to establish an operational penalty \nwhereby, after the second misoperation of necessary control technologies and/or \nprotection systems, PJM will terminate the transmission service agreement with the \nEligible Customer taking Interim NITS, FCD transmission service, or NFCD \ntransmission service on behalf of Eligible Load.  We direct PJM to file, within 60 days of \nthe date of issuance of this order, a compliance filing to revise its Tariff consistent with \nthese findings.  \n We agree with PJM that there are significant reliability risks associated with \nmisoperation of special protection schemes, and that “financial penalties, alone, are not \nsufficient to incentivize Eligible Customers to comply with . . . control technology and \nprotection system obligations.”1043  We find that this replacement rate serves to deter \nconduct contrary to the fundamental principle around which the new transmission \nservices created by the Commission were based, i.e., that Eligible Customers taking \nservice on behalf of Co-Located Loads are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions.1044  Moreover, we \nagree with PJM that, after the first misoperation of necessary control technologies and/or \nprotection systems, suspension of service for a period of up to 120 days is reasonable to \nallow for an analysis by PJM, and the affected transmission owner(s) as necessary, of the \noperational performance of the necessary control technologies and/or protection systems.  \n \n1043 PJM Initial Brief at 41-42, 45, 50. \n1044 December Order, 193 FERC ¶ 61,217 at P 177 (“we also find that PJM’s \nTariff is unjust and unreasonable because it does not include transmission services that \nreflect Eligible Customers taking service on behalf of Co-Located Loads that are willing \nand able to limit their energy withdrawals from the transmission system under certain \nconditions.”); see id. P 205 (“We note that, in general, special protection schemes allow \nEligible Customers on behalf of Co-Located Load to effectively limit their withdrawals \nfrom the transmission system.  For these reasons, in these instances where the                       \nCo-Location Arrangement includes special protection schemes that limit its energy \nwithdrawals, we find that it is a just and reasonable replacement rate to allow an Eligible \nCustomer taking transmission service on behalf of such load to take and be charged for \nnew types of transmission service that are alternatives, and not equivalent, to NITS.”)."},{"page":234,"startToken":91496,"endToken":91938,"text":"Docket No. EL25-49-002, et al. \n- 234 - \nIn response to the Indicated TOs, we find that it is reasonable that the Tariff provide that \nservice may resume following PJM’s approval, as well as the relevant transmission \nowner’s approval of the necessary control technologies and/or protection systems for \nconsistency with the transmission owner’s technical standards. \n However, we reject PJM’s proposal not to apply such a penalty to Eligible \nCustomers taking FCD transmission service on behalf of Co-Located Load, consistent \nwith our findings above that Eligible Customers taking FCD transmission service on \nbehalf of Co-Located Load must also have necessary control technologies and/or \nprotection systems to limit their energy withdrawals from the transmission system to their \ncontract demand level.1045  We also disagree with protesters’ arguments opposing PJM’s \nproposal to establish an operational penalty for misoperation of necessary control \ntechnologies and/or protection systems.  Vistra suggests that PJM’s proposal unduly \ndiscriminates against Co-Location Arrangements as compared to other entities using \nspecial protection schemes, but this penalty proposal (which Vistra mistakenly alleges \napplies only to special protection schemes) is not relevant to existing transmission \nservices in PJM.1046  By contrast, as discussed above, correct operation of necessary \ncontrol technologies and/or protection systems is foundational to the new transmission \nservices.  Vistra’s separate claim that PJM’s proposal is unduly discriminatory “insofar as \nit treats unreserved use of the transmission system by point-to-point customers differently \nfrom unreserved use by customers taking these new transmission services” is misplaced.  \nIn contrast to Eligible Customers taking Interim NITS, FCD transmission service, and/or \nNFCD transmission service on behalf of Eligible Load, PTPS customers are not required \nto establish necessary control technologies and/or protection systems in order to take \nPTPS.1047  We also find unpersuasive Joint Co-Location Developers’ allegation that this \noperational penalty is even more excessive, as compared to a penalty for failure to follow \ncurtailment or load shedding directives, because misoperation without withdrawal does \nnot risk system harm.1048  We agree with PJM that “[w]hen a control technology or \nprotection scheme misoperates, there can be serious consequences.”1049  Where PJM \n \n1045 See supra Part VI.C. \n1046 See PJM Initial Brief at 47 (justifying its proposal to allow that an Eligible \nCustomer disqualified from the new transmission services may take NITS because \n“NITS, in and of itself, addresses Curtailment, Load Shed, and control technology or \nprotection scheme misoperation risk”). \n1047 Id. at 50 (“PJM supports a penalty for unreserved use in addition to the \ndisqualification and pause-in-rules discussed above.”); see id. at 41 (Table 1 (Penalties)). \n1048 Joint Co-Location Developers Response Brief at 26. \n1049 PJM Initial Brief at 43, 45; PJM Reply Brief at 52-53."},{"page":235,"startToken":91938,"endToken":92356,"text":"Docket No. EL25-49-002, et al. \n- 235 - \nplans and operates the system around an assumption that necessary control technologies \nand/or protection systems will work, unexpected system behavior due to misoperation \nrisks system reliability regardless of whether withdrawals occur, and we find that it is \nreasonable not to rely only on financial penalties to mitigate these risks. \n We disagree with Constellation’s suggestion that the Commission should adopt \nSPP’s approach from CHILLS, which contains only penalties for exceeding the \ntransmission customer’s reserved capacity,1050 but not suspension or disqualification, for \nthe same reasons discussed above.   \n We agree with NOVEC that PJM’s proposed penalty language to disqualify the \nEligible Customer as a whole from taking the relevant transmission service is not just and \nreasonable.  Instead, we direct PJM to propose on compliance Tariff provisions providing \nthat, after the second misoperation of necessary control technologies and/or protection \nsystems pertaining to a transmission service agreement governing an Eligible Customer \ntaking Interim NITS, FCD transmission service, and/or NFCD transmission service on \nbehalf of Eligible Load, PJM will terminate the transmission service agreement.  The \nEligible Customer could still take transmission service, including Interim NITS, FCD \ntransmission service, and NFCD transmission service, on behalf of other loads through \nother transmission service agreements. \n ODEC asserts that PJM’s implementation of its penalties must not subject ODEC \nor its member distribution cooperatives to service interruptions or disqualification, or \nfinancial penalties, as a result of requiring ODEC to serve as the Eligible Customer.  The \nCommission set a replacement rate in the December Order applicable to Eligible \nCustomers taking transmission service on behalf of Co-Located Load.  The operational \n(and financial) penalties we establish in this order apply to Eligible Customers who elect \nto take the new transmission services on behalf of Eligible Load and who do not comply \nwith the terms and conditions of the new transmission services, including misoperation of \nnecessary control technologies and/or protection systems.  The December Order does not \nrequire that Eligible Customers on behalf of Co-Located Load take one of the new \ntransmission services and they may choose to take NITS instead.  The Co-Located Load \ncannot force an Eligible Customer to take a type of transmission service it does not wish \nto take.  As the Commission explained in the December Order, NITS remains a just and \nreasonable transmission service option that an Eligible Customer on behalf of a                     \nCo-Located Load may choose.1051   \n \n1050 Sw. Power Pool, Inc., 195 FERC ¶ 61,196 at 98. \n1051 December Order, 193 FERC ¶ 61,217 at P 195."},{"page":236,"startToken":92356,"endToken":92796,"text":"Docket No. EL25-49-002, et al. \n- 236 - \nc. \nUnreserved Use of the Transmission System \n We find that it is just and reasonable to impose a financial penalty on an Eligible \nCustomer taking any of the new transmission services on behalf of Eligible Load for \nunreserved use of the transmission system.  We find that it is just and reasonable to use \nIndicated TOs’ two-part penalty framework and to apply, within that framework, a \npenalty rate that is twice the rate we establish in this order for FCD transmission \nservice.1052  Indicated TOs propose a base penalty charge for each hour in which the \nEligible Customer’s reserved service limit is exceeded at the Point of Interconnection \nduring at least one five-minute interval (Exceedance Hour) and a penalty ratchet when \nexceedances occur repeatedly.1053  Specifically, Indicated TOs propose that, if more than \none Exceedance Hour occurs on the same day, then an additional daily penalty applies; if \nexceedances occur on multiple days within the same week, an additional weekly penalty \napplies; if exceedances occur in multiple weeks within the same month, then an \nadditional monthly penalty applies; and if exceedances occur in multiple months within \nthe same year, then an additional annual penalty applies.1054  We agree with Indicated \nTOs that progressively increasing the consequences of repeated penalties encourages \nEligible Customers to manage their usage consistent with their reserved transmission \nservice limit.1055  We note that Indicated TOs submit testimony indicating that they \npropose to distribute revenues collected from financial penalty charges on a monthly \nbasis to Eligible Customers taking NITS and FCD transmission service.  However, we \nfind that unreserved use penalties should be distributed to all non-offending transmission \n \n1052 See Order No. 890, 118 FERC ¶ 61,119 at P 848 (“As a result, we establish a \nrebuttable presumption that unreserved use penalties no greater than twice the firm   \npoint-to-point rate for the penalty period defined above are just and reasonable.”); id.       \nP 846 (basing penalty charges on the period of unreserved use and determining that, as a \ngeneral rule, more than one assessment for a given duration will increase the penalty \nperiod to the next longest duration). \n1053 Indicated TOs Response Brief at 12 (“When a Co-Located Load exceeds its \nreserved transmission service limit, the base penalty charge will be assessed for any hour \nin which at least one five-minute interval occurs during which a customer’s metered load \nat the point of interconnection exceeds its reserved transmission service.”); Indicated TOs \nReply Brief at 16. \n1054 Indicated TOs Reply Brief at 16; Indicated TOs Reply Brief, Ex.                  \nNo. PTO-0005 at 7. \n1055 Indicated TOs Response Brief at 12-13; Indicated TOs Reply Brief at 17."},{"page":237,"startToken":92796,"endToken":93157,"text":"Docket No. EL25-49-002, et al. \n- 237 - \ncustomers consistent with Order No. 890.1056  We direct the PJM transmission owners \nto file, within 60 days of the date of issuance of this order, a compliance filing consistent \nwith these findings.  \nE. \nAnti-Toggling Mechanisms for Firm Contract Demand Transmission \nService \n In the December Order, the Commission found that FCD transmission service \nshould have a minimum term of one year, but that PJM should propose an anti-toggling \nmechanism for Eligible Customers switching between FCD and NFCD transmission \nservice.1057 \n1. \nInitial Briefs \n PJM proposes an anti-toggling mechanism to prevent transmission customers from \nswitching between FCD and NFCD transmission services by providing that the portion of \nthe Co-Located Load served by FCD transmission service is not eligible to be served by \nNFCD transmission service for five years following the effective date of the Service \nAgreement.  Conversely, PJM explains, it does not bar Co-Located Load served by \nNFCD transmission service from being served by FCD transmission service in future \nyears.  However, PJM proposes an exception if there is a physical change to the                    \nCo-Located Generator that would materially alter the MW level dedicated to the load or \nto the Co-Located Load that would materially alter the MW level of its gross demand.1058  \nPJM argues this exception is necessary to ensure that, if an Eligible Customer materially \nchanges either the generation capacity or the load on a gross demand basis, the Tariff \nprovides flexibility to determine whether FCD or NFCD transmission service should be \ntaken for the new incremental portion. \n PJM also maintains that its proposed 42-month notice of termination acts as an \nanti-toggling device in a manner similar to the five-year commitment period applicable to \nthe Fixed Resource Requirement alternative in the PJM capacity market.  PJM explains \nthat its notice period recognizes that PJM incorporates these loads in the capacity market, \n \n1056 See Order No. 890, 118 FERC ¶ 61,119 at P 860 (“Unreserved use penalties \nare assessed against transmission customers and should, therefore, be distributed to all \nnon-offending transmission customers, whether affiliated with the transmission provider \nor not.”). \n1057 December Order, 193 FERC ¶ 61,217 at P 213. \n1058 PJM Initial Brief at 53-54."},{"page":238,"startToken":93157,"endToken":93495,"text":"Docket No. EL25-49-002, et al. \n- 238 - \nand it would unreasonably shift costs to other loads if Co-Located Loads could avoid \ncapacity charges incurred on their behalf by terminating service prematurely.1059 \n Indicated TOs propose a five-year minimum commitment period for FCD \ntransmission service, arguing that doing so is necessary to ensure that FCD transmission \nservice customers cannot trigger Network Upgrades and then cease taking service, \nthereby potentially shifting costs to other transmission customers, and because it mirrors \nthe commitment period for loads seeking to procure their own capacity.1060  Indicated \nTOs argue that, where Network Upgrades are attributable to FCD transmission service \ncustomers, separate payment guarantees may be required to prevent Network Customers \nfrom being left “holding the bag” if an FCD transmission service customer exits the \nsystem before the costs of the Network Upgrades are fully paid.1061  Finally, Indicated \nTOs recommend that the Commission adopt the same requirements for FCD transmission \nservice that apply to notices of termination for NITS, including the 42-month notice \nperiod.1062 \n2. \nResponse Briefs \n NOVEC states that it supports PJM’s five‑year minimum service commitment and \n42‑month notice requirement.  NOVEC asserts that the minimum service commitment \nsends timely price signals to the capacity market, enhances market stability, and \nminimizes upgrade‑related risks if a Co-Located Load withdraws.  NOVEC notes that the \nnotice-of-termination period is identical to the requirements for termination of NITS and \nprevents Co-Located Loads from avoiding capacity charges by prematurely terminating \ntheir agreement.1063 \n3. \nDetermination \n Except as noted below, we find PJM’s proposed anti-toggling mechanism to be a \njust and reasonable replacement rate.  In particular, we find that PJM’s proposal to \nprohibit, for a period of five years, Eligible Customers taking transmission service on \nbehalf of a Co-Located Load from taking NFCD transmission service for any portion of \n \n1059 Id. at 54-55. \n1060 Indicated TOs Initial Brief at 21 (citing December Order, 193 FERC ¶ 61,217 \nat P 213). \n1061 Id. at 21 n.50. \n1062 Id. at 21 & n.52. \n1063 NOVEC Response Brief at 15-16."},{"page":239,"startToken":93495,"endToken":93864,"text":"Docket No. EL25-49-002, et al. \n- 239 - \nCo-Located Load served by FCD transmission service will ensure that such Eligible \nCustomers do not attempt such a switch based on expected capacity market conditions, \nconsistent with the December Order.1064  We further find that PJM’s proposed 42-month \nnotice of termination provision applicable to FCD transmission service customers mirrors \nthat applicable to Network Customers and recognizes that PJM has procured capacity on \ntheir behalf.  We direct PJM to file, within 60 days of the date of issuance of this order, a \ncompliance filing to revise its Tariff consistent with these findings. \n However, we find PJM’s proposed exceptions regarding changes to the                     \nCo-Located Generator or Co-Located Load are not just and reasonable to the extent they \nwould permit Eligible Customers to decrease the level of contract demand for FCD \ntransmission service they take on behalf of an Eligible Load, and increase the level of \ncontract demand for NFCD transmission service, without being subject to the                     \nanti-toggling provision.  The Commission found that the anti-toggling mechanism should \nensure Eligible Customers taking transmission service on behalf of Co-Located Loads \ncannot switch from FCD to NFCD transmission service based on expected capacity \nmarket conditions.1065  As such, PJM’s proposal is not consistent with the December \nOrder, and we direct PJM to propose an anti-toggling mechanism without an exception \nfor Eligible Customers taking FCD transmission service on behalf of Eligible Load in a \ncompliance filing within 60 days of the date of issuance of this order.  \n We also reject Indicated TOs’ proposal for a five-year minimum commitment \nperiod.  As Indicated TOs acknowledge, the Commission required in the December Order \nthat the minimum term for FCD transmission service should be one year.1066  As such, we \nfind that Indicated TOs’ arguments in support of its proposal are an untimely request for \nrehearing of the December Order.1067 \n \n1064 December Order, 193 FERC ¶ 61,217 at P 213. \n1065 Id. \n1066 Id. \n1067 See, e.g., ISO New Eng. Inc., 132 FERC ¶ 61,098 at P 12 (“The Commission \nhas held that requests to alter a compliance filing in a manner that differs from the order \nrequiring the compliance filing constitute a collateral attack on the order requiring the \ncompliance filing.”)."},{"page":240,"startToken":93864,"endToken":94210,"text":"Docket No. EL25-49-002, et al. \n- 240 - \nF. \nCommunications, Alarm, SCADA, or Other Requirements \n1. \nInitial Briefs \n PJM proposes to develop telemetry requirements for Co-Located Load so that \nPJM can monitor the status of demand placed on PJM’s transmission system, including \nunreserved use, to ensure reliability.1068  PJM states that it still determining the scope of \nthe tools and requirements necessary to limit withdrawals that exceed reserved use.  PJM \nalso proposes to develop data exchange and metering requirements for Co-Located Load \nthat may be similar to those applicable to generation.  PJM proposes to develop the \ncapability to differentiate more granularly between the transmission services available to \nEligible Customers on behalf of Co-Located Load because they are prioritized \ndifferently.  PJM maintains that Eligible Customers would need to take these different \nforms of transmission service on different feeders, or cables leaving substations, to \nultimately serve the Co-Located Load. \n PJM next proposes to develop requirements and identify any relevant NERC rules \nto ensure that relay settings are consistent with the design of the necessary control \ntechnologies and/or protection systems, as set forth in each Service Agreement.1069  PJM \nasserts that transmission owners must be heavily involved in ensuring that necessary \ncontrol technology and/or protection systems are properly designed.  PJM explains that it \nproposes technical requirements that must be in place prior to commencement of service \nbecause there are significant risks introduced by the necessary control technology and \nprotection systems.  PJM also proposes to make changes to core Markets and Operations \nsystems to incorporate the information provided by Eligible Customers and Co-Located \nLoad to ensure reliability of the PJM transmission system.  \n2. \nResponse Briefs \n Indicated TOs support PJM’s proposal in its initial brief to develop telemetry \nrequirements and require Co-Located Load to meet such requirements in order to monitor \nCo-Located Loads’ use of the transmission system.1070 \n3. \nDetermination \n We decline to direct PJM’s proposed telemetry, data exchange, metering, and \nrelay setting requirements as the replacement rate because PJM has not provided \n \n1068 PJM Initial Brief at 59-61. \n1069 Id. at 60-61. \n1070 Indicated TOs Response Brief at 10-11."},{"page":241,"startToken":94210,"endToken":94624,"text":"Docket No. EL25-49-002, et al. \n- 241 - \nsufficient detail to find they are just and reasonable.  PJM by its own admission has not \nfinished determining the scope of what might be necessary to limit energy withdrawals \nfrom the transmission system.  Accordingly, and consistent with our determination above \nto extend the three new transmission services set forth in the December Order to Eligible \nCustomers taking service on behalf of load with BTMG that are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions, we \ndirect PJM to file, within 60 days of the date of issuance of this order, a compliance filing \nwith Tariff revisions it deems necessary for PJM to be able to ensure that an Eligible \nCustomer has adequate telemetry, data exchange, and metering requirements such that \nPJM may monitor the Eligible Load’s use of the transmission system, limit withdrawals, \nand ensure relay settings are consistent with necessary control technologies and/or \nprotection systems. \nG. \nCurtailment Procedures for Interim NITS and Non-Firm Contract \nDemand Transmission Service \n1. \nInitial Briefs \n PJM proposes that Interim NITS and NFCD transmission service will be curtailed \nbefore FCD transmission service and NITS.1071  PJM also proposes that it may curtail \nInterim NITS or NFCD transmission service prior to dispatching the Pre-Emergency \nLoad Response Program or in response to a transfer capability shortage as a result of \nsystem reliability conditions.  PJM proposes that FCD transmission service be treated \nequal to NITS for purposes of curtailment.1072  PJM states that it reserves the right to \ncurtail the three new transmission services on a non-discriminatory basis for the purpose \nof making necessary adjustments to, changes in, or repairs on its lines, substations, and \nfacilities, and in cases where continuation of service would endanger persons or property.  \nPJM proposes that the Eligible Customer must shed load in accordance with previously \nestablished procedures under the relevant Service Agreement. \n PJM acknowledges that its system does not differentiate between different types of \ntransmission service because all load within PJM is currently served by NITS.1073  Thus, \nPJM explains, core systems would need to be implemented to enable sufficient \ngranularity when shedding an Eligible Customer’s Co-Located Load being served by two \ndifferent levels of transmission service, i.e., both FCD and NFCD transmission services.  \nPJM clarifies that, assuming these core system design changes can be implemented, \nEligible Customers taking transmission service on behalf of Co-Located Load would \n \n1071 PJM Initial Brief at 63. \n1072 Id. at 64. \n1073 Id. at 65-66."},{"page":242,"startToken":94624,"endToken":94982,"text":"Docket No. EL25-49-002, et al. \n- 242 - \nneed to take different forms of transmission service on different feeders, or cables leaving \nsubstations, to ultimately serve Co-Located Load. \n2. \nResponse Briefs \n Joint Co-Location Developers argue that PJM fails to adequately clarify when and \nhow NFCD transmission service and Interim NITS shall be curtailed, in particular the \ncurtailment trigger.1074  Joint Co-Location Developers maintain that the curtailment \ntrigger significantly affects rates and service and is realistically susceptible of \nspecification and should be included in the tariff.  Joint Co-Location Developers assert \nthat PJM does not clarify whether and how it will determine curtailment priority among \nits different classes of non-firm service, including Non-Firm PTPS, NFCD transmission \nservice, and Interim NITS. \n Constellation argues that it is discriminatory to require different feeders and would \nunnecessarily delay Co-Location Arrangements.1075  At minimum, Constellation asserts \nthat such a requirement should not apply in the case of Interim NITS since the                       \nCo-Located Load is not taking both firm and non-firm service. \n AEU/SEIA explain that the December Order established a curtailment hierarchy in \naccordance with which Interim NITS and NFCD transmission service will be curtailed \nbefore NITS and FCD transmission service and before pre-emergency demand response \nresources are dispatched.1076  AEU/SEIA claim that PJM’s implementation of this \nhierarchy is contradictory because PJM states that it “may” curtail Interim NITS and \nNFCD transmission service prior to dispatching the Pre-Emergency Load Response \nProgram and that it “will” curtail Interim NITS and NFCD transmission service before \ndemand response resources are called upon to reduce load.1077  AEU/SEIA argue that this \ninconsistency must be resolved because a customer considering whether to take Interim \nNITS or NFCD transmission service needs to know whether curtailment before                      \npre-emergency demand response is a certainty or a possibility. \n AEU/SEIA contend that PJM has provided no information about the conditions \nthat would actually trigger curtailment of Interim NITS or NFCD transmission service in \npractice and that, because these are novel services, no historical curtailment data \n \n1074 Joint Co-Location Developers Response Brief at 17. \n1075 Constellation Response Brief at 29-30. \n1076 AEU/SEIA Response Brief at 11. \n1077 Id. (citing PJM Initial Brief at 63-64)."},{"page":243,"startToken":94982,"endToken":95307,"text":"Docket No. EL25-49-002, et al. \n- 243 - \nexists.1078  AEU/SEIA further argue that modeling of expected curtailment frequency and \nduration or examples of how curtailment would operate for a hypothetical Co-Location \nArrangement must be provided in order for customers to make informed business \ndecisions on the transmission service that best serves their needs.  If it is not, AEU/SEIA \nargue that prospective customers will default to taking NITS.  AEU/SEIA request that the \nCommission require PJM to develop and publish historical analysis and forward-looking \nmodeling of curtailment frequency and duration for Interim NITS and NFCD \ntransmission service, as informed by historical system conditions in PJM and broken \ndown by zone.  AEU/SEIA also argue that PJM should set out in its reply brief how it \nintends to operationalize curtailment for NFCD transmission service, including the \nsequence in which Co-Located Loads will be curtailed relative to other non-firm services \nand the mechanism by which curtailment instructions will be communicated and \nenforced.  Without this sequence, AEU/SEIA claim that neither the Commission nor \naffected parties can evaluate whether PJM’s proposed curtailment framework is \nconsistent with the December Order’s requirement that NFCD transmission service be \navailable “as needed during normal, non-emergency system operating conditions.”1079 \n3. \nReply Briefs \n Earthjustice argues that the Commission should require PJM to clarify how and \nwhen PJM will enforce its curtailment procedures, including:  (1) how PJM will \ncommunicate its curtailment directives; (2) how and when transmission providers will \ndetermine that load shed is necessary, which loads will be curtailed first, and at what \nstage curtailments will occur; and (3) how a data center will be disqualified and the \ntimeline for that disqualification.1080   \n Industrials/Amtrak argue that many traditional large loads cannot shut off \nimmediately if their on-site generation trips.1081   \n \n1078 Id. at 12-14. \n1079 Id. at 14 (quoting December Order, 193 FERC ¶ 61,217 at P 215). \n1080 Earthjustice Reply Brief at 14, 16. \n1081 Industrials/Amtrak Reply Brief at 6."},{"page":244,"startToken":95307,"endToken":95698,"text":"Docket No. EL25-49-002, et al. \n- 244 - \n4. \nAnswers \n Constellation argues that PJM inappropriately attempts in its reply brief to \nreinstate a curtailment criterion of a capacity/reserve shortage and that the Commission \nrejected this element of PJM’s proposed Option 7 in the December Order.1082   \n5. \nDetermination \n We find PJM’s proposed curtailment hierarchy for Interim NITS, FCD \ntransmission service, and NFCD transmission service to be just and reasonable.  PJM’s \nproposal to treat FCD transmission service as comparable to NITS is consistent with the \nDecember Order,1083 as is PJM’s proposal to curtail Interim NITS and NFCD \ntransmission service prior to firm transmission services.1084  In addition, we find PJM’s \nproposal to curtail Interim NITS and NFCD transmission service prior to deployment of \nits Pre-Emergency Load Response Program, or in response to a transfer capability \nshortage as a result of system reliability conditions, to be just and reasonable because it is \nconsistent with how Non-Firm PTPS is curtailed.1085  We disagree with Constellation that \nPJM’s proposal to curtail Interim NITS during capacity or reserve shortages is \ninconsistent with the Commission’s findings in the December Order that PJM’s proposed \nconstruct for an interim transmission service was too broad and not sufficiently detailed \nto direct as a replacement rate.1086  Constellation misunderstands the December Order, \nwhich found it was not reasonable to allow the transitional period for Interim NITS to \ncontinue until any resource adequacy challenges associated with the addition of the     \nCo-Located Load were addressed, and instead limited the transitional period to the time \n \n1082 Constellation May 11 Answer at 13 (citing December Order, 193 FERC \n¶ 61,217 at P 202). \n1083 See, e.g., December Order, 193 FERC ¶ 61,217 at P 208 (stating that FCD \ntransmission service will have the same curtailment priority as existing firm transmission \nservices). \n1084 See, e.g., id. P 201 (stating that Interim NITS “will be curtailed before existing \nfirm transmission services and the new Firm Contract Demand Transmission Service”); \nid. P 215 (stating same with respect to NCFD transmission service). \n1085 See PJM, Intra-PJM Tariffs, OATT, § II, § 14.7 (Curtailment or Interruption of \nService) (0.0.0) (describing PJM’s curtailment procedures for Non-Firm PTPS); PJM \nManual 13:  Emergency Operations, Rev. 97 (eff. November 20, 2025), § 2.3.2. \n1086 Constellation May 11 Answer at 13 (citing December Order, 193 FERC \n¶ 61,217 at P 202)."},{"page":245,"startToken":95698,"endToken":96106,"text":"Docket No. EL25-49-002, et al. \n- 245 - \nneeded to complete any Network Upgrades identified in the study process.1087  The \nCommission did not find, as Constellation alleges, that Interim NITS could not be \ncurtailed as a result of capacity or reserve shortages.  Here, we find that PJM’s proposal \nto curtail Interim NITS during capacity or reserve shortages is just and reasonable and \nconsistent with both the nature of the transmission service as a non-firm transmission \nservice for which Eligible Customers do not pay generation capacity charges, and the \nneed to maintain reliability. \n We disagree with commenters that PJM must provide specific details in its Tariff, \nsuch as the trigger and procedures for curtailment of Interim NITS and FCD or NFCD \ntransmission services, or how PJM will enforce its curtailment procedures.  We find that \nrequiring PJM to specify the curtailment priority of these new transmission services in its \nTariff, while leaving specific implementation details in its manuals and individual service \nagreements, provides transmission customers sufficient certainty as to their priority \nrelative to other transmission services and ensures that PJM has sufficient flexibility to \npreserve system reliability in varying operating conditions.1088  We find that it is just and \nreasonable and important to protect transmission system reliability to provide PJM with \nsufficient operational flexibility during emergency procedures to curtail transmission \ncustomers as needed to preserve reliability.1089 \n However, we find that PJM does not adequately explain its curtailment hierarchy \namongst non-firm transmission services.  For example, while PJM states that it will \ncurtail Interim NITS and NFCD transmission service prior to deployment of its           \nPre-Emergency Load Response Program, it does not detail if these transmission services \nwill be curtailed before or after Non-Firm PTPS, or if curtailment priority within NFCD \ntransmission service will be based on duration, as are curtailments for Non-Firm \nPTPS.1090  \n \n1087 December Order, 193 FERC ¶ 61,217 at P 202. \n1088 See PJM, Intra-PJM Tariffs, OATT, § II.14.7 Curtailment or Interruption of \nService (0.0.0) (describing PJM’s curtailment procedures for Non-Firm PTPS). \n1089 See Order No. 890-A, 121 FERC ¶ 61,297 at P 566 (“If the [conditional firm \ntransmission] customer selects the annual hourly cap option, the transmission provider \nwill have the flexibility to conditionally curtail the customer for any reliability reason \nduring those hours, including but not limited to, the system condition(s) identified in the \nsystem impact study.”). \n1090  PJM, Intra-PJM Tariffs, OATT, § II.14.7 Curtailment or Interruption of \nService (0.0.0)."},{"page":246,"startToken":96106,"endToken":96533,"text":"Docket No. EL25-49-002, et al. \n- 246 - \n We also find that PJM has not justified its assertion that an Eligible Customer \ntaking different forms of transmission service on behalf of Co-Located Load would need \nto take those services on different feeders.  PJM states that this requirement is based on \nthe need for core systems to be implemented to enable sufficient granularity when \nshedding an Eligible Customer’s Co-Located Load being served by two different levels \nof transmission service.1091  While we recognize that core systems will need to be \nimplemented, PJM provides no explanation as to why these systems could not be \nsufficiently flexible as to accommodate a single feeder with two different levels of \ntransmission service on it. 1092  \n Accordingly, we direct PJM to submit, within 60 days of the date of issuance of \nthis order, a compliance filing to revise the Tariff to include the curtailment priorities for \nInterim NITS, FCD transmission service, and NFCD transmission service consistent with \nour findings above.  This language must specify that FCD transmission service shall be \ntreated the same as NITS for the purposes of curtailment, and that Interim NITS and \nNFCD transmission service will be curtailed prior to deployment of PJM’s Pre-\nEmergency Load Response Program, or in response to a transfer capability shortage as a \nresult of system reliability conditions.  PJM’s submittal must also detail the curtailment \npriorities between Non-Firm PTPS, Interim NITS, and NFCD transmission service, \nincluding how or if PJM will prioritize transmission customers for curtailment based on \nduration of service.  Consistent with our determination above to extend the three new \ntransmission services set forth in the December Order to Eligible Customers taking \nservice on behalf of load with BTMG that are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions, we further direct \nPJM to reflect this change in its compliance filing. \nH. \nRates, Terms, and Conditions for Interim NITS \n1. \nInitial Briefs \n PJM proposes to model the non-rate terms and conditions for Interim NITS on \nNITS.1093  PJM proposes that an Eligible Customer may take Interim NITS on behalf of \nCo-Located Load until Network Upgrades are complete, and then the customer will \nautomatically convert to a Network Customer.  PJM states that an Eligible Customer \nreceiving Interim NITS on behalf of Co-Located Load will receive non-firm transmission \n \n1091 PJM Initial Brief at 66. \n1092 For example, this system could assume that load on a feeder is firm up until \nthe Eligible Customer’s Firm Contract Demand withdrawal limit, and non-firm above \nthat contract demand amount. \n1093 PJM Initial Brief at 67-70."},{"page":247,"startToken":96533,"endToken":96945,"text":"Docket No. EL25-49-002, et al. \n- 247 - \nservice for the delivery of energy to Co-Located Load.  PJM proposes that, upon receipt \nof request, PJM will determine the amount of Interim NITS that can be reliably provided \nbased on the results of appropriate studies and in consultation with the affected \ntransmission owner.  PJM proposes that, for Interim NITS, the Eligible Customer must \nmeet certain conditions and appropriate technical requirements.  PJM proposes that the \nEligible Customer have an ongoing obligation to notify PJM of material changes in the \ndemand characteristics of the Co-Located Load and the supply characteristics of the Co-\nLocated Generator.  PJM explains that the Co-Location Arrangement cannot change \nduring the term of the Interim NITS without discussion and possible further studies by \nPJM. \n PJM proposes load shedding and curtailment provisions applicable to Interim \nNITS, including that prior to commencement of service, the Eligible Customer must \ndemonstrate its ability to comply with PJM’s load shedding and curtailment \nprocedures.1094  PJM proposes to require Eligible Customers taking Interim NITS to work \nwith PJM and the affected transmission owners to establish necessary control \ntechnologies and/or protection systems.  PJM proposes that Eligible Customers will be \nassessed certain non-transmission-related rates, including:  (1) administrative service \ncharges, (2) ancillary services charges except for regulation, (3) black start service \ncharges based on gross demand, and (4) any redispatch costs.  PJM proposes a single \nService Agreement specific to Eligible Customers serving Co-Located Load via Interim \nNITS or NITS.  Indicated TOs propose to apply the NITS rate to Eligible Customers \ntaking Interim NITS.1095 \n2. \nResponse Briefs \n Indicated TOs propose several clarifications to PJM’s illustrative Tariff \nprovisions.1096  First, Indicated TOs propose revisions to section 702.4 to require an \nEligible Customer to satisfy any applicable technical requirements imposed by the \nrelevant transmission owner.  Second, Indicated TOs propose revisions to section 703.2 \nto clarify that both new and increased Co-Located Loads will be studied pursuant to a \nnew application for transmission service.  Third, Indicated TOs contend that PJM should \nprovide additional information as to what would constitute a “material change” in the \ndemand characteristics of a Co-Located Load for purposes of an Eligible Customer’s \nnotice obligations under section 703.3.  Fourth, Indicated TOs recommend that PJM \nestablish load shedding practice guidelines applicable to Co-Location Arrangements for \npurposes of load shedding conducted under section 705.3 of PJM’s illustrative tariff \n \n1094 Id. at 71-75. \n1095 Indicated TOs Initial Brief at 5 n.13.  \n1096 Indicated TOs Response Brief at 13-17, 23."},{"page":248,"startToken":96945,"endToken":97391,"text":"Docket No. EL25-49-002, et al. \n- 248 - \nprovisions.  Indicated TOs explain that they are particularly concerned with automatic \nload shedding schemes because of the possibility that unintentional activation of these \nschemes may result in unwanted shedding of nearby customer loads in addition to the   \nCo-Located Load.  Fifth, Indicated TOs propose revisions to section 705.5 to require that \nthe necessary control technologies and/or protection systems that must be approved by \nPJM are also approved by and developed in accordance with the transmission owners’ \ninterconnection standards, guidelines, and practices.  Sixth, Indicated TOs assert that the \nreference to the transmission owner’s cost responsibility for redispatch costs in                 \nsection 706.2 of PJM’s illustrative tariff provisions is incorrect and request that PJM \nremove such reference from the filed Tariff records.  Seventh, Indicated TOs propose to \ncorrect a typo to the conditions of Part XI of the Tariff in section 2.0 of PJM’s proposed \nAttachment F-3A.  Last, Indicated TOs request that PJM add a placeholder section for \nlisting required control technologies and/or protection systems to section 4.0 of PJM’s \nproposed Attachment F-3A.  \n Vistra argues that PJM’s study process is flawed because it provides too much \ndiscretion to PJM and transmission owners to determine whether studies are required, \nwhich studies to conduct, the timeline for doing so, and how to prioritize different \nrequests.1097  Also, Vistra contends that PJM’s proposal is unclear on what it means to \nensure that non-firm transmission service can be provided reliably, and that it is critical \ncustomers seeking non-firm service not be held to some higher standard.  Constellation \nsimilarly argues that PJM’s proposed study procedures lack sufficient detail to prevent \ndelay and discrimination by transmission owners.1098  Constellation argues that PJM must \nspell out the studies it will perform in the tariff, as well as the timetable for completing \nthe studies.  \n Market Monitor argues that Interim NITS is not consistent with PJM’s planning \nprocess and poses potentially significant reliability risks due to the complexity introduced \nby the necessary control technology and protection systems.  Market Monitor states that \nthese risks mean there is not an unlimited amount of Interim NITS that can be provided, \nwhich raises questions about which customers would be allowed to take Interim NITS if \ndemand exceeds supply.1099 \n Several parties oppose any restriction on Co-Located Loads accessing on-site \ngeneration while using Interim NITS and being curtailed, noting that PJM’s initial brief is \nnot clear on whether such a requirement is being proposed.  Parties argue that such a \nrequirement would be in violation of the December Order and significantly degrade the \n \n1097 Vistra Response Brief at 31, 39. \n1098 Constellation Response Brief at 14-15. \n1099 Market Monitor Response Brief at 6-7."},{"page":249,"startToken":97391,"endToken":97693,"text":"Docket No. EL25-49-002, et al. \n- 249 - \nvalue of Interim NITS.1100  DCC argues that allowing customers to be curtailed despite \nbringing their own generation does not align with the Commission’s objective to enable \nmore flexible and timely service arrangements for Co-Located Load.1101  DCC argues \nthat PJM’s proposal does not recognize an intermediate operational state in which Co-\nLocated Generators can operate in parallel with the grid on a limited, non-exporting or                       \nnon-market-participating basis while completing interconnection requirements.  \nEnchanted Rock argues that because this limitation during curtailment conditions is a \npractice that affects rates and service significantly, that is reasonably susceptible of \nspecification, and that is not so generally understood in any contractual arrangement as to \nrender recitation superfluous, it must be included within the Tariff in order to be \neffectuated.1102   \n AEU/SEIA request that the Commission direct PJM to revise its Interim NITS \nproposal to explicitly allow Eligible Customers to use on-site generation to serve load \ncontinuously, provided that the generator is new and that the Co-Located Load does not \nsimultaneously withdraw energy from the transmission system.1103  Joint Co-Location \nDevelopers assert that, as long as Co-Located Generators are not capacity resources, they \nshould be free to serve Co-Located Loads during curtailment conditions.1104   \n Constellation asks the Commission to direct PJM to include a transitional \nmechanism for pending large load NITS applicants so that this new service is not \nunnecessarily limited to new applicants.1105 \n \n1100 See AEU/SEIA Response Brief at 20 (citing December Order, 193 FERC \n¶ 61,217 at P 201); Enchanted Rock Response Brief at 7; Joint Co-Location Developers \nResponse Brief at 18. \n1101 DCC Response Brief at 3-4.  \n1102 Enchanted Rock Response Brief at 7. \n1103 AEU/SEIA Response Brief at 21. \n1104 Joint Co-Location Developers Response Brief at 19. \n1105 Constellation Response Brief at 14."},{"page":250,"startToken":97693,"endToken":98116,"text":"Docket No. EL25-49-002, et al. \n- 250 - \n3. \nReply Briefs \n In consideration of parties’ comments, particularly those of Indicated TOs, PJM \nproposes certain revisions to the illustrative tariff provisions for Interim NITS and NITS, \nand the Service Agreement for Interim NITS.1106 \n PJM articulates several reasons why Interim NITS customers should not be \nallowed to access the Co-Located Generator when PJM curtails the Co-Located Load.1107  \nFirst, PJM states that Interim NITS will be curtailed when the system cannot support it in \nreal time, whether with sufficient generation or transmission capacity.  Second, PJM \nargues that Interim NITS must be designed to allow PJM to maintain system reliability, \nboth from a transmission and capacity perspective, and that allowing an interruptible \ncustomer to preclude PJM from accessing a generation resource during times of system \nstress would be contrary to that objective.  PJM maintains that, if the Co-Located \nGenerator is a capacity resource, then PJM has the first call on such resource’s energy to \nmeet the region’s needs.  Third, PJM explains that Interim NITS is a type of NITS and is \nserved by the pool of resources and not any one dedicated resource.  PJM asserts that \nallowing an Interim NITS customer to take energy from the Co-Located Generator during \ncurtailment would effectively transform this service into something akin to FCD or \nNFCD transmission service, where the Co-Located Generator dedicates a MW level of \noutput to the Co-Located Load.  Lastly, PJM argues that Interim NITS is predicated on \nthe Co-Located Load’s willingness to curtail, and allowing an Interim NITS customer \naccess to the Co-Located Generator during times of system stress is contrary to this \nfoundational element of the December Order.1108  PJM also asserts that providing a right \nto an Interim NITS customer to access the Co-Located Generator during times of system \nstress is illogical when such right is not available to full Network Customers.  NOVEC \nurges the Commission to accept PJM’s proposal and argues that if prospective customers \nfind that Interim NITS is not desirable, they have the flexibility to pursue a combination \nof FCD and NFCD transmission services.1109 \n PJM defends its process for Interim NITS to determine whether “additional studies \nare needed” by arguing that the NITS study could provide sufficient information for PJM \nto determine if Interim NITS can be reliably provided.1110  PJM maintains that it should \n \n1106 PJM Reply Brief at 60-64. \n1107 Id. at 16-20. \n1108 Id. at 21 (citing December Order, 193 FERC ¶ 61,217 at P 201). \n1109 NOVEC Reply Brief at 16. \n1110 PJM Reply Brief at 27."},{"page":251,"startToken":98116,"endToken":98477,"text":"Docket No. EL25-49-002, et al. \n- 251 - \nnot be required to provide as much detail for Interim NITS determinations as for FCD \nand NFCD transmission services given that Interim NITS is derivative of the customer’s \nexisting NITS request and associated studies, although the illustrative tariff authorizes \nPJM to perform additional studies if needed.1111   \n Joint Co-Location Developers argues that the Interim NITS proposal undermines \nPJM’s reliability rationale for NFCD transmission service outage restrictions because \nPJM has proposed to make it broadly available during normal operating conditions, and \nPJM has not claimed that doing so will compromise reliability.1112 \n Constellation avers that PJM’s omission of any detail with respect to this study \nprocess does not comply with the Commission’s directive to provide additional record \nevidence to set the appropriate replacement rates, terms, and conditions for Interim NITS \nand urges the Commission to direct PJM to file its study process for Interim NITS within \n30 days.1113 \n4. \nAnswers \n Constellation asks the Commission to direct PJM to revise its illustrative tariff to \nclarify that large loads with pending NITS applications shall be studied for Interim NITS \nat the request of the load without having to submit a separate application.1114 \n Enchanted Rock reiterates that PJM’s implementation of Interim NITS is \nfundamentally flawed because, while an Eligible Customer takes Interim NITS on behalf \nof a Co-Located Load, PJM proposes not to allow that Co-Located Load to receive any \ncapacity or energy from a Co-Located Generator and instead to treat the Co-Located \nGenerator as a capacity resource.1115  Enchanted Rock disagrees with PJM that this \nlimitation accords with the principles of the December Order that the new transmission \nservices are designed to serve loads that are willing and able to control their withdrawals \nfrom the transmission system and to allow PJM to maintain system reliability.  Enchanted \nRock avers to the contrary that allowing a Co-Located Load to take capacity and energy \nfrom a Co-Located Generator enables that Co-Located Load to control its withdrawals \n \n1111 Id. at 31-32. \n1112 Joint Co-Location Developers Reply Brief at 9-10. \n1113 Constellation Reply Brief at 12. \n1114 Constellation May 11 Answer at 14. \n1115 Enchanted Rock May 7 Answer at 2-3."},{"page":252,"startToken":98477,"endToken":98907,"text":"Docket No. EL25-49-002, et al. \n- 252 - \nfrom the transmission system.1116  Enchanted Rock also contends that PJM is mistaken in \nits argument that the PJM region has first call on the output of a Co-Located Generator \nbefore the Co-Located Generator has completed PJM’s interconnection study process and \nreceived a GIA, because until that point, the Co-Located Generator is not eligible to be a \ncapacity resource.  Enchanted Rock argues that forcing the Co-Located Generator to be \ndispatched under emergency conditions during this period would be unduly \ndiscriminatory by imposing on these Co-Located Generators obligations that are not \nimposed on similarly situated generators.1117  Finally, Enchanted Rock argues that it \nwould be illogical that an Interim NITS customer not be allowed to rely on its non-firm \nCo-Located Generator in order to remain online during emergencies when it is taking \nnon-firm transmission service.  Enchanted Rock further contends that it would be unjust \nand unreasonable for a Co-Located Load to bear the full capital and development risk of \nbringing a Co-Located Generator online only for PJM to dispatch the Co-Located \nGenerator to serve firm Network Customers during emergencies—precisely when PJM is \nserving firm Network Customers but curtailing Interim NITS customers.1118 \n5. \nDetermination \n We find PJM’s proposal for Interim NITS to be just and reasonable, subject to the \nclarifications directed below, and direct PJM to file, as the replacement rate, rates, terms, \nand conditions for Interim NITS as detailed below on compliance.  We generally agree \nwith PJM that the non-rate terms and conditions for Interim NITS reflect those applied to \nNITS, with necessary modifications to reflect the interim and non-firm nature of this new \ntransmission service.  We find that PJM’s proposals that an Eligible Customer taking \nInterim NITS will receive non-firm transmission service for the delivery of energy to    \nCo-Located Load and convert automatically to a Network Customer when Network \nUpgrades are complete to be consistent with the directives in the December Order.1119  \nWe direct PJM to file, within 60 days of the date of issuance of this order, a compliance \nfiling revising its Tariff consistent with these findings.  Consistent with our determination \nabove to extend the three new transmission services set forth in the December Order to \nEligible Customers taking service on behalf of load with BTMG that are willing and able \n \n1116 Id. at 5-6. \n1117 Id. at 6-8. \n1118 Id. at 8-9. \n1119 December Order, 193 FERC ¶ 61,217 at P 200 (stating that Interim NITS “can \nbe interrupted until the Network Upgrades necessary to provide NITS are complete and \nthe Co-Located Load can be designated as Network Load”)."},{"page":253,"startToken":98907,"endToken":99349,"text":"Docket No. EL25-49-002, et al. \n- 253 - \nto limit their energy withdrawals from the transmission system under certain conditions, \nwe further direct PJM to reflect this change in its compliance filing. \n   We find that Indicated TOs’ proposal to apply the NITS rate to Eligible \nCustomers taking Interim NITS on behalf of Co-Located Load is just and reasonable and \nconsistent with the December Order.1120  Therefore, and consistent with our \ndetermination above to extend the three new transmission services set forth in the \nDecember Order to Eligible Customers taking service on behalf of load with BTMG that \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions, we direct the PJM transmission owners to submit, within 60 days of \nthe date of issuance of this order, a compliance filing to apply the NITS rate to Eligible \nCustomers taking transmission service on behalf of Eligible Loads.   \n Consistent with our findings in Part VI.A.4, we also find just and reasonable \nPJM’s proposal to charge Eligible Customers taking Interim NITS on behalf of                    \nCo-Located Load certain administrative and ancillary services charges, and to assess \ncharges based on gross demand for regulation and black start service.  We find PJM’s \nproposal consistent with the December Order.1121  Moreover, we find it is just and \nreasonable to charge Interim NITS customers redispatch costs to cover congestion-related \ncosts, given that Interim NITS will be pool-scheduled and can be served by generators \nredispatched to mitigate congested transmission paths.  Accordingly, and consistent with \nour determination above to extend the three new transmission services set forth in the \nDecember Order to Eligible Customers taking service on behalf of load with BTMG that \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions, we direct PJM to submit, within 60 days of the date of issuance of this \norder, a compliance filing to incorporate in the Tariff revisions to assess to Eligible \nCustomers taking transmission service on behalf of Eligible Loads:  (1) administrative \nservice charges, (2) ancillary service charges, (3) black start service charges,                          \n(4) regulation charges, and (5) any redispatch costs.   \n We note that only curtailment procedures were explicitly included in the paper \nhearing, and Tariff provisions governing other terms and conditions for Interim NITS, \nincluding the study process, should be filed on compliance.1122  That said, we find it is \njust and reasonable to allow PJM greater discretion as to how it studies Interim NITS \n \n1120 Id. (stating that Interim NITS customers would pay the NITS rate). \n1121 Id. (stating that Interim NITS customers would pay ancillary service charges \nand charges for black start service). \n1122 Id. P 219."},{"page":254,"startToken":99349,"endToken":99824,"text":"Docket No. EL25-49-002, et al. \n- 254 - \nrequests, in comparison to requests for FCD transmission service.1123  We disagree with \nVistra that PJM’s proposed study process provides too much discretion to PJM and \ntransmission owners.  We reiterate that Interim NITS is only “available to the extent PJM \ndetermines that it can provide some level of interim service reliably,”1124 and therefore \nwe find that it is just and reasonable to limit this service to situations in which PJM, in \nconsultation with transmission owners, grants such service based on the results of \nappropriate studies.  The Commission generally defers to transmission providers’ \ndiscretion regarding how to maintain a reliable transmission system.1125   \n We further find that Interim NITS is distinguishable from FCD and NFCD \ntransmission services, for which we direct PJM to provide additional detail in the Tariff \nregarding the study process as discussed Part VI.A.3, because Interim NITS is a \ntemporary service akin to provisional interconnection service in that both services are \nintended to allow a customer to temporarily use an amount of a service that can be \nprovided reliably until such customer may begin taking the full requested service.  In \nboth cases, the Commission requires the transmission provider to determine if the \nrequested service could be provided reliably.1126  Similar to provisional interconnection \n \n1123 See PJM, Intra-PJM Tariffs, OATT, § VIII.L 439 Provisional Interconnection \nService (0.0.0) (providing that PJM “may grant such service at its discretion based upon \nan evaluation that will consider the results of available studies”); Order No. 890,                    \n118 FERC ¶ 61,119 at P 957 (in the case that a request for long-term Firm PTPS cannot \nbe satisfied out of existing capacity, the transmission provider is required to identify \noptions for providing service but has discretion to study and offer a mix of planning \nredispatch and conditional firm options for a single service request). \n1124 December Order, 193 FERC ¶ 61,217 at P 200. \n1125 RWE Clean Energy, LLC, 194 FERC ¶ 61,212 at P 42 (“The Commission \ngenerally allows transmission providers to exercise their engineering judgment when \nconducting interconnection studies, including deferring to transmission providers’ \ndiscretion regarding how to maintain a reliable transmission system.”). \n1126 December Order, 193 FERC ¶ 61,217 at P 200 (“Moreover, this new service \nwould be optional for an Eligible Customer seeking NITS on behalf of a Co-Located \nLoad and would only be available to the extent PJM determines that it can provide some \nlevel of interim service reliably.”); Order No. 845, 163 FERC ¶ 61,043 at P 440 (“In \nresponse to CAISO, we clarify that ‘a certain amount of capacity already studied’ refers \nto situations where, for example, available studies or additional studies as necessary \nindicate that there is a certain amount of interconnection service available without the \nneed for additional network upgrades and the transmission provider can reliably \naccommodate the interconnection service.”)."},{"page":255,"startToken":99824,"endToken":100343,"text":"Docket No. EL25-49-002, et al. \n- 255 - \nservice, we find that it is just and reasonable, in the case of this new interim transmission \nservice, to afford PJM greater discretion as to how it decides to study Interim NITS \nrequests, in comparison to requests for FCD and NFCD transmission services, and thus \nwe decline to direct PJM to provide more detail in its Tariff on the process for studying \nrequests for Interim NITS.1127  We also disagree with Constellation that it is necessary for \nPJM to study requests for Interim NITS as part of the NITS process, rather than pursuant \nto a separate application.  On compliance, we direct PJM to file Tariff provisions to \neffectuate a study process for Interim NITS, as discussed herein.  Consistent with our \ndetermination above to extend the three new transmission services set forth in the \nDecember Order to Eligible Customers taking service on behalf of load with BTMG that \nare willing and able to limit their energy withdrawals from the transmission system under \ncertain conditions, we further direct PJM to reflect this change in its compliance filing.   \n Regarding requests from parties that Interim NITS customers be allowed access to \nthe Co-Located Generator during curtailments, we find that it is just and reasonable to \nprohibit the Eligible Customer taking Interim NITS on behalf of Co-Located Load from \ndrawing energy from the Co-Located Generator when the Eligible Customer is curtailed, \nif the Co-Located Generator is a capacity resource.  As PJM explains, capacity resources \nhave an obligation to serve Network Load, and this obligation is particularly important \nduring emergency or pre-emergency conditions when PJM needs all resources at its \ndisposal to maintain reliability.1128  However, in response to parties, we clarify that such a \nrestriction would not be applicable to an Eligible Customer taking Interim NITS on \nbehalf of Co-Located Load if the associated Co-Located Generator does not yet have any \ninterconnection service or has only provisional interconnection service.  Further, this \nrestriction applicable to an Eligible Customer taking Interim NITS on behalf of             \nCo-Located Load would not be applicable if the associated Co-Located Generator is \nseeking capacity resource status, but not yet obtained such status, because that Co-\nLocated Generator would not yet have any obligation to provide capacity under the \n \n1127 See PJM, Intra-PJM Tariffs, OATT, § VIII.L 439 Provisional Interconnection \nService (0.0.0) (providing that PJM “may grant such service at its discretion based upon \nan evaluation that will consider the results of available studies”); RWE Clean Energy v. \nPJM Interconnection, L.L.C., 194 FERC ¶ 61,212 at P 42 (“The Commission generally \nallows transmission providers to exercise their engineering judgment when conducting \ninterconnection studies, including deferring to transmission providers’ discretion \nregarding how to maintain a reliable transmission system.”); Order No. 890, 118 FERC   \n¶ 61,119 at P 957 (in the case that a request for long-term Firm PTPS cannot be satisfied \nout of existing capacity, the transmission provider is required to identify options for \nproviding service but has discretion to study and offer a mix of planning redispatch and \nconditional firm options for a single service request). \n1128 PJM Reply Brief at 18."},{"page":256,"startToken":100343,"endToken":100829,"text":"Docket No. EL25-49-002, et al. \n- 256 - \nTariff.  We therefore direct PJM to submit, within 60 days, a compliance filing to \nincorporate the rates, terms, and conditions for Interim NITS that includes clarifications \nto specify that (1) an Eligible Customer taking Interim NITS on behalf of Co-Located \nLoad may be served by a Co-Located Generator that is seeking capacity resource status \nduring a curtailment condition to the extent that Co-Located Generator has yet to obtain \ninterconnection service or has only provisional interconnection service, and (2) an \nEligible Customer on behalf of Co-Located Load cannot expect to be served by a                  \nCo-Located Generator that is a capacity resource during a curtailment condition.  \nConsistent with our determination above to extend the three new transmission services set \nforth in the December Order to Eligible Customers taking service on behalf of load with \nBTMG that are willing and able to limit their energy withdrawals from the transmission \nsystem under certain conditions, we further direct PJM to reflect this change in its \ncompliance filing. \n We disagree with Market Monitor’s arguments that Interim NITS is not consistent \nwith PJM’s transmission planning process and poses potentially significant reliability \nrisks.  As discussed above, we adopt PJM’s proposal for application and studies for \nInterim NITS, which limits the amount of Interim NITS available to an Eligible Customer \nseeking to take Interim NITS on behalf of a Co-Located Load to the amount that PJM, in \nconsultation with the affected transmission owner(s), determines can be provided reliably \nto that customer while maintaining the reliability of the transmission system.   \n We decline to adopt Constellation’s proposal to include a transitional mechanism \nfor pending NITS applications.  PJM’s proposal does not prohibit any NITS applicant \nfrom also applying for Interim NITS, provided the applicant pays the additional study fee \nand is subject to the technical requirements for Interim NITS.  Therefore, we find such a \ntransitional mechanism not to be necessary.   \nI. \nAnnual Report on New Transmission Services \n Having addressed the rates, terms, and conditions for each of the new transmission \nservices (subject to additional compliance), we now turn to our ongoing oversight of the \nimplementation and use of these new transmission services.  As discussed in the \nDecember Order and reiterated today, we expect that these new transmission services will \nfacilitate more efficient use of the existing transmission system and limit unnecessary \ntransmission system buildout.  However, we also recognize that the new transmission \nservices represent new developments in the provision of transmission service in the PJM \nregion.  These developments require effective oversight and monitoring to help ensure \nthe transmission services are working as intended and do not create reliability issues or \nraise novel questions regarding application of cost causation principles.  Transparent \ninformation on the use of the new transmission services is also important for prospective \nEligible Customers on behalf of Eligible Loads to assess which transmission service to \nrequest and where on the transmission system to make such requests.  We conclude that"},{"page":257,"startToken":100829,"endToken":101131,"text":"Docket No. EL25-49-002, et al. \n- 257 - \nthe Commission, states, PJM market participants, and stakeholders would benefit from \nadditional transparency about these new transmission services, and we therefore direct \nPJM to prepare an annual report, posted to its website, containing information about the \ndemand for and use of these new transmission services.  Accordingly, we direct PJM to \nsubmit, as part of its compliance filing within 60 days of the date of issuance of this \norder, proposed Tariff provisions requiring such a report and a proposal for the \ninformation to be included in that annual report.  \n As PJM considers the scope and content of that annual report, we propose that the \nfollowing information could aid the Commission, states, PJM market participants, and \nstakeholders in assessing the impact of the new transmission services: \n1) Data regarding each transmission service request seeking each of the new services \nby transmission zone, including:1129 \na. Peak gross load of the Eligible Load \nb. Category of the Eligible Load \nc. Type and MW of transmission service being requested \nd. Type and MW of transmission service granted  \ne. Dates of reservation and usage (for non-firm services) \n2) Total MW of each type of transmission service taken each year by transmission \nzone, including: \na. Total amount of FCD transmission service taken relative to peak gross load \nat the meter receiving FCD transmission service  \nb. Total amount of NFCD transmission service taken relative to peak gross \nload at the meter receiving NFCD transmission service  \nc. Total amount of Interim NITS relative to peak gross load at the meter \nreceiving Interim NITS  \n \n1129 Some of the information we identify here is likely to be available on PJM’s \nOpen Access Same-Time Information System.  PJM may account for that availability in \ndesigning its proposal and addressing the potential burden associated with preparing the \nannual report."},{"page":258,"startToken":101131,"endToken":101458,"text":"Docket No. EL25-49-002, et al. \n- 258 - \n3) Information about transmission revenues paid by Eligible Customers on behalf of \nEligible Loads for each transmission service by transmission zone, including: \na. Total revenues paid by Eligible Customers taking each service per \ntransmission zone \nb. Percentage of each transmission owner’s total revenue requirement paid via \nrevenues from each new service \nc. MWs of each new transmission service taken by Eligible Customers \nserving Eligible Loads as a percentage of peak gross load for each \ntransmission owner \n4) Frequency and magnitude of curtailment from the reservation of NFCD \ntransmission service and Interim NITS by transmission zone \n5) Frequency and magnitude of denials of NFCD transmission service reservation \nrequests by transmission zone  \nJ. \nProposed Effective Date \n1. \nInitial Briefs \n PJM proposes an effective date of June 1, 2029, for the three new transmission \nservices.  PJM advances two rationales for its proposal:  (1) integration of the new \ntransmission services into PJM’s capacity market so that PJM can procure capacity for \nEligible Customers taking FCD transmission service on behalf of Co-Located Loads \ncannot occur until 2029; and (2) necessary modifications to the PJM core markets and \noperations software will take time.1130  PJM also argues that this effective date will not be \na limiting factor because Eligible Customers taking the new transmission services on \nbehalf of Co-Located Load and their Co-Located Generators likely will not be online \nbefore June 1, 2029, given interconnection requirements, supply chain issues, \nprocurement challenges, and capacity auction timelines.1131 \n As to the capacity market, PJM argues that demand associated with Co-Located \nLoads will significantly affect PJM’s load forecast and thus have significant implications \nfor the capacity market.  PJM explains, however, that while the BRA for the 2028/2029 \ndelivery year (beginning June 1, 2028) has not taken place, the load forecast and eligible \n \n1130 PJM states this includes Real-Time Security Constrained Economic Dispatch, \nDay-Ahead Market, and dispatch software.  PJM Initial Brief, Horger Aff. ¶ 16. \n1131 PJM Initial Brief at 79-82."},{"page":259,"startToken":101458,"endToken":101839,"text":"Docket No. EL25-49-002, et al. \n- 259 - \ncapacity have already been determined, and it is no longer possible to implement changes \nbefore the BRA is conducted.  Therefore, according to PJM, the 2029/2030 delivery year \n(beginning June 1, 2029) is the first BRA in which the effects of the new transmission \nservices can be considered and PJM can procure capacity for Eligible Customers taking \nFCD transmission service on behalf of Co-Located Loads.1132 \n As to the technical implementation issues, PJM argues that implementing the \nproposed curtailment priorities applicable to Interim NITS and NFCD transmission \nservice will require modifying PJM’s economic dispatch software and dispatch tools in \norder to incorporate system automation that will avoid undesirable outcomes.  PJM \nfurther contends that work cannot begin until the rates, terms, and conditions of these \nnew transmission services are finalized, and that changes to these systems will be \ndependent on vendor availability, the speed with which systems changes can be designed, \nand interaction with other software changes.1133 \n2. \nResponse Briefs \n Some parties support PJM’s proposed effective date.  Market Monitor argues that \nall load in PJM currently is served by NITS, and that PJM has demonstrated that it must \nsignificantly modify core systems to address curtailing load where an Eligible Customer \ntakes more than one kind of transmission service on behalf of Co-Located Load.1134  \nNOVEC contends that entities other than PJM must also prepare for these new \ntransmission services by making operational adjustments and regulatory and billing \nchanges to ensure costs reflect cost causation principles.1135 \n Constellation, DCC, Joint Co-Location Developers, and Vistra oppose PJM’s \nproposed effective date, and make a variety of arguments against PJM’s rationales for it \nor in favor of alternative proposals for faster implementation.1136  As to arguments PJM \nmakes about the capacity market, Vistra contends that resource adequacy considerations \n \n1132 Id. at 79-80 (citing Horger Aff. ¶¶ 11-13).  PJM also argues that inclusion of \nthese services in Incremental Auctions would be inappropriate because they are \nconducted to procure replacement resources and generally result in small adjustments.  \nId. at 80-81 (citing Horger Aff. ¶ 15). \n1133 Id. at 81; Horger Aff. ¶ 16. \n1134 Market Monitor Response Brief at 8. \n1135 NOVEC Response Brief at 17-18. \n1136 Constellation Response Brief at 7; Joint Co-Location Developers Response \nBrief at 28; Vistra Response Brief at 8-9."},{"page":260,"startToken":101839,"endToken":102281,"text":"Docket No. EL25-49-002, et al. \n- 260 - \nare beyond the scope of a transmission provider’s obligation to serve and that the \nCommission requires transmission providers to make transmission service decisions \nbased on available transfer capacity.1137  Constellation, Joint Co-Location Developers, \nand Vistra each criticize PJM on the basis that Interim NITS and NFCD transmission \nservice are not capacity-backed services such that PJM need not procure capacity on their \nbehalf.  Joint Co-Location Developers contend that PJM does not explain why a customer \ntaking NITS would be reflected in capacity market demand forecast but a customer \ntaking FCD transmission service would not.  Similarly, Vistra argues that large loads \nwere already included in the load forecasts for the 2027/2028 and 2028/2029 BRAs and \nthat some of the new large loads in the forecasts may take the new transmission services.  \nJoint Co-Location Developers argue that, if PJM’s concerns stem from a planning need \nassociated with existing capacity resources de-registering, then PJM should propose a \ndelayed implementation limited to particular use cases.  \n As to PJM’s technical implementation issues, Vistra and Joint Co-Location \nDevelopers criticize PJM for failing to offer any specificity.1138  Vistra alleges that \nprevious experience, such as in PJM’s implementation of Order No. 841, suggests that \nPJM should be able to implement software changes much more quickly.  Vistra further \ncharges that the Commission should demand more support to justify delaying \nimplementation than PJM has provided here, as it did in prior cases such as MISO’s \nimplementation of Order No. 2222.  Similarly, Joint Co-Location Developers argue that \ncurtailable products can be implemented on much faster timelines, pointing in particular \nto SPP’s CHILLS and PJM’s planned Connect and Manage proposal.  Vistra also argues \nthat PJM’s systems should already be capable of curtailing because its Tariff provides \nNon-Firm PTPS.  Joint Co-Location Developers assert that PJM does not explain why \nadditional software must be developed for FCD transmission service, which is similar to \nNITS.  Lastly, Joint Co-Location Developers state that their attached testimony notes that \nleveraging price responsive demand modifications to security constrained economic \ndispatch could allow PJM to implement faster any security constrained economic \ndispatch changes for non-firm loads.  \n Several parties disagree with PJM that Co-Located Generators will not be online \nbefore June 1, 2029.1139  Joint Co-Location Developers argue that there are likely to be \nprojects already in development that may opt to use these new transmission services.  \n \n1137 Vistra Response Brief at 7 (citing, e.g., Order No. 890, 118 FERC ¶ 61,119               \nat P 2). \n1138 Id. at 10-12; Joint Co-Location Developers Response Brief at 29-30. \n1139 Joint Co-Location Developers Response Brief at 30; Vistra Response Brief              \nat 9-10; Constellation Response Brief at 8."},{"page":261,"startToken":102281,"endToken":102706,"text":"Docket No. EL25-49-002, et al. \n- 261 - \nVistra adds that some generators are not capacity resources, are already in the process of \nde-listing, or could enter into a bilateral agreement with another generator to cover its \ncapacity obligation.  Constellation points out that load co-locating with existing \ngeneration could take Interim NITS.  \n Several parties request that the Commission make all or certain of the new \ntransmission services available earlier.1140  DCC argues that PJM has not demonstrated \nthat all elements of the proposed services must be deferred for several years, nor has it \nidentified opportunities for phased or interim implementation.  DCC argues that the \nCommission should consider whether certain components of the framework can be \nimplemented on an accelerated or staged basis to provide near-term benefits while \nlonger-term systems are developed.  Joint Co-Location Developers ask the Commission \nto require that FCD transmission service be available within six months of an order \naccepting PJM’s filing and NFCD transmission service and Interim NITS be available at \nthe earliest date technically feasible. \n Constellation urges the Commission to establish a separate track to approve rates \nand terms for Interim NITS and make them effective no later than October 1, 2026.1141  \nConstellation argues that PJM offers no legitimate reason for proposing a                             \nthree-and-a-half-year delay and argues that it should not be difficult to adopt as soon as \npossible.  Constellation maintains that, if the Commission separates and implements \nInterim NITS on a fast track, potential logistical challenges will not risk delay.  \nConstellation suggests that the Commission review FCD and NFCD transmission \nservices on a separate track and urges the Commission not to delay them until June 2029.  \nVistra proposes that, even if the Commission accepts PJM’s software-based justifications, \nthe Commission should require PJM to immediately accommodate Co-Location \nArrangements for which software changes are irrelevant, such as where the Eligible \nCustomer does not reserve any amount of NFCD transmission service on behalf of       \nCo-Located Load.1142  Vistra asserts that, whereas PJM contends that it needs software \nupgrades to apply appropriate curtailment priorities, a customer that reserves zero MWs \nof transmission service has no service to curtail.  Vistra contends that it is not just and \nreasonable to prevent service on the basis of a software upgrade that is, at best, nominally \nrelevant to that service.  Vistra maintains that delaying service to customers that pull no \nenergy from the grid is inconsistent with the December Order’s goal to remedy PJM’s \n \n1140 DCC Response Brief at 9; Joint Co-Location Developers Response Brief                 \nat 27-28. \n1141 Constellation Response Brief at 6-9. \n1142 Vistra Response Brief at 12-14."},{"page":262,"startToken":102706,"endToken":103098,"text":"Docket No. EL25-49-002, et al. \n- 262 - \nfailure to provide transmission service reflecting a Co-Located Load’s willingness and \nability to limit withdrawals.   \n3. \nReply Briefs \n PJM asserts that NFCD transmission service is not easy to implement from an \noperations perspective, particularly at scale, and in addition to exposing the system to \nhigher reliability risks, will also require PJM to modify key systems.1143  PJM explains \nthat changes to Energy Management Systems are needed to ensure that PJM’s systems \nare able to properly account for the provision of energy to Co-Located Load in the               \nday-ahead and real-time market.  PJM contends that its Energy Management System does \nnot currently distinguish between different types of load, and that feature must be added.  \nPJM argues that it must determine how to properly model and reflect NFCD transmission \nservice and Co-Located Load in the different systems given that NFCD transmission \nservice requires the transmission system to operate on reduced contingency margins.  \nPJM maintains that significant modifications to the market clearing engines used in both \nthe day-ahead and real-time markets will be required because PJM must be able to curtail \nNFCD transmission service with little to no advanced notification to respond to \nsignificant SOL/IROL exceedances. \n Separate from systems updates, PJM argues that it will still be challenging from an \noperational perspective to provide NFCD transmission service.1144  PJM explains that its \nsystems must not only accurately reflect how this new service affects the transmission \nsystem, but PJM must also account for this service in the Operating Plans and then \nimplement those plans manually when needed in real time.  PJM argues that, because the \ntransmission system is not designed to accommodate NFCD transmission service, it will \nlikely trigger many more SOL/IROL exceedances for PJM to mitigate in the Operating \nPlan and require operations at or near operating limits, rendering the system less flexible \nto respond to unexpected changes during operations.  PJM contends that it will be \nimperative that loads taking NFCD transmission service can be removed from the system \nas soon as possible when needed. \n PJM claims it will need additional tariff language and manuals to operationalize \nrequests for service.1145  PJM asserts that it reserves the right to further supplement the \nrecord in this proceeding if and when it develops such tariff language. \n \n1143 PJM Reply Brief at 13-14. \n1144 Id. at 14-15. \n1145 Id. at 16."},{"page":263,"startToken":103098,"endToken":103482,"text":"Docket No. EL25-49-002, et al. \n- 263 - \n PJM clarifies that June 1, 2029, is the effective date for providing the new \ntransmission services and that, once the Commission establishes the terms and conditions \nfor these new services, PJM is willing to start accepting service requests and processing \nservice applications.1146  PJM states its intent to get a headstart on establishing the details \nas to how it would implement the illustrative tariff by soon commencing discussions with \nstakeholders regarding implementation details, to be stated in PJM manuals, for these \nnew transmission services.  PJM contends that, with these clarifications, there is no need \nto establish a transition mechanism for pending NITS applications, as Constellation \nsuggests.  In response to concerns that PJM failed to provide a specific timeline for \nsoftware development, PJM contends that it cannot determine a more exact development \nschedule at this time because these are new transmission services.  \n Some commenters continue to support PJM’s proposed effective date.1147  Other \ncommenters continue to criticize PJM’s proposed effective date.  Joint Co-Location \nDevelopers argue that it is unclear why PJM must delay implementation until 2029, given \nthat ERCOT has committed to implementation of controllable load as soon as 2027.1148  \nJoint Co-Location Developers further argue that PJM has provided no reason why its \nsystem uniquely requires a longer implementation process compared to other RTOs, and \nthat PJM is well placed to implement changes to its security constrained economic \ndispatch given the existing capability of its nodal Price Responsive Demand \nimplementation. \n Constellation argues that PJM’s proposed effective date would impose a three- to \nfive-year moratorium on Co-Location Arrangements and undermines the December \nOrder by allowing rates found to be unjust and unreasonable to remain in place for \nyears.1149  Constellation asserts that PJM has devoted significant resources to such \nchanges and has the tools to implement new rules quickly.  Constellation urges the \nCommission to promptly approve the rates and terms for Interim NITS, including the \nstudy process, by no later than October 1, 2026.   \n \n1146 Id. at 55-57. \n1147 NOVEC Reply Brief at 27; Earthjustice Reply Brief at 19.  \n1148 Joint Co-Location Developers Reply Brief, Supp. Aff. of Andrew Levitt and \nAniruddh Mohan at 10 (citing ERCOT Large Load Interconnection Batch Study \nWorkshop #7 at 25 (April 9, 2026), ERCOT-Large-Load-Batch-Study-Workshop7-\n20260409_v03.pptx). \n1149 Constellation Reply Brief at 3-5."},{"page":264,"startToken":103482,"endToken":103903,"text":"Docket No. EL25-49-002, et al. \n- 264 - \n4. \nAnswer \n Constellation opposes PJM’s requested effective date and points out that PJM \nseeks to begin Connect and Manage July 1, 2027, to allow the interconnection of                 \nnon-capacity-backed loads that are potentially interruptible during capacity shortages, \nunless the load brings its own generation.1150  Constellation contends that it is not \ncredible that PJM will take more than three years to implement Interim NITS, but less \nthan one year to commence Connect and Manage.1151  Constellation asks the Commission \nto make Interim NITS effective no later than October 1, 2026, so that service can begin \nno later than June 1, 2027. \n5. \nDetermination \n We find that PJM has not provided sufficient information for the Commission to \nfind that its proposed June 1, 2029, effective date is just and reasonable.  We are \nconcerned that the proposed June 1, 2029, effective date unduly delays the availability of \nthe new transmission services, particularly those where PJM does not procure generation \ncapacity for Eligible Customers taking the transmission service on behalf of Eligible \nLoad, i.e., Interim NITS and NFCD transmission service.  As discussed above, while \nPJM will procure generation capacity in forward capacity auctions to serve Eligible \nCustomers taking FCD transmission service based on the contract demand level, PJM \nwill not consider Interim NITS or NFCD transmission service in its resource adequacy \nplanning.  Further, we agree with Vistra and Joint Co-Location Developers that PJM’s \nproposal lacks specificity.  In particular, we find that the implementation details for the \nsoftware updates necessary for PJM’s economic dispatch software and dispatch tools lack \nspecificity.  Though PJM states that it cannot determine “a more exact development \nschedule” for software development,1152 the Commission generally requires more support \nfor the timeliness of a proposed effective date.1153  We believe that the instant order \nprovides PJM further clarity.  We note that June 1, 2029, is approximately three years \nfrom now, and the issues raised by this proceeding, including those pertaining to          \nCo-Located Load, are urgent in nature and, therefore, merit serious consideration of an \nearlier effective date.  Therefore, we direct PJM to reconsider its proposed effective date \nof June 1, 2029.  Moreover, we direct PJM to make a compliance filing, due within                 \n60 days of the date of issuance of this order, in which PJM must explain whether it can \n \n1150 Constellation May 11 Answer at 2. \n1151 Id. at 3. \n1152 PJM Reply Brief at 57. \n1153 See, e.g., Midcontinent Indep. Sys. Operator, Inc., 190 FERC ¶ 61,031,              \nat P 163 & n.302 (2025)."},{"page":265,"startToken":103903,"endToken":104193,"text":"Docket No. EL25-49-002, et al. \n- 265 - \nmake the new transmission services available on different effective dates.  In the \ncompliance filing, PJM should specifically discuss whether Interim NITS and NFCD \ntransmission service can be made effective at an earlier date for Eligible Customers \ntaking transmission service on behalf of Eligible Loads.  \nK. \nAdditional Arguments \n1. \nBehind the Meter Generation \na. \nReply Briefs \n Industrials/Amtrak argue that the Commission should take the following actions:  \n(1) set a realistic retail BTMG threshold to focus new Co-Located Load rules on \n“gridbusting” growth above 200-300 MW, not on existing industrial customers (e.g., \nconsumer goods manufacturers, steel mills, chemical manufacturers, paper mills, and \npharmaceutical factories); (2) qualify all QFs for retail BTMG treatment without a date \nlimit, consistent with PURPA regulations; (3) set clear grandfathering rules to enable \nexisting, established users to avoid intensive PJM study queues, study deposits, and \nprocesses for operations that continue to function properly.1154 \n PJM argues that certain parties raise issues beyond the scope of this proceeding.  \nPJM contends that Industrials/Amtrak improperly ask the Commission to examine \nBTMG.1155 \nb. \nDetermination \n Industrials/Amtrak raise issues with respect to PJM’s retail BTMG netting rules \nthat we address in PJM’s second compliance filing above.1156 \n2. \nReliability Backstop Auction \na. \nReply Briefs \n Maryland OPC asserts that PJM’s proposed terms and conditions do not explain \nhow existing capacity resources that shift to Co-Location Arrangements with new data \ncenters would be treated relative to the PJM’s proposed reliability backstop procurement \n(RBP).  For example, Maryland OPC states that it is unclear whether capacity from \nexisting generators that remove themselves from the capacity market and enter                  \n \n1154 Industrials/Amtrak Reply Brief at 15. \n1155 PJM Reply Brief at 58-59. \n1156 See supra Part V.A."},{"page":266,"startToken":104193,"endToken":104583,"text":"Docket No. EL25-49-002, et al. \n- 266 - \nCo-Location Arrangements with new data center load would need to be replaced with \nnew capacity through the RBP or in the regular BRA, and whether new data center load \nthat co-locates with an existing generator will be included in the cost allocation of the \nRBP.1157  Maryland OPC states that if the capacity of existing generation that shifts to \nserve new co-located data center load is added to the BRA, ratepayers would be saddled \nwith enormous costs that should be assigned to the Co-Located Load, in contravention of \nthe White House and PJM Governors’ Statement of Principles and the White House’s \nRatepayer Protection Pledge.  Maryland OPC requests that the Commission at minimum \nrequire PJM demonstrate how its proposal meets ratepayer protection standards set forth \nin the Statement of Principles and Ratepayer Protection Pledge and defer action on the \nproposed revisions until after PJM proposes tariff revisions to implement its RBP.  \nMaryland OPC also raises concern that PJM’s initial brief suggests PJM does not intend \nfor existing load to be eligible for the new transmission services.1158 \nb. \nDetermination \n As an initial matter, we clarify that, contrary to Maryland OPC’s concern, PJM’s \npaper hearing proposal does not restrict Eligible Customers on behalf of existing          \nCo-Located Load from taking the new transmission services.  We decline Maryland \nOPC’s request to defer action.  Maryland OPC expresses concern that PJM’s paper \nhearing proposal does not address how existing capacity resources that seek to serve    \nCo-Located Loads would be treated relative to a potential future filing by PJM to address \nits reliability backstop mechanism.  We find that Maryland OPC’s concerns about PJM’s \ncapacity market are beyond the scope of this paper hearing, which addresses the rates, \nterms, and conditions for new transmission services for Eligible Customers to take on \nbehalf of Eligible Loads.1159     \n \n1157 Maryland OPC Reply Brief at 9-11. \n1158 Id. at 8 (noting PJM’s explanation that it is unlikely that new generation will \nbe operational before its proposed June 1, 2029 effective date). \n1159 In recognition of the goal to prevent unfair cost shifts, we also note that as part \nof the President’s Ratepayer Protection Pledge, a number of computational loads have \ncommitted to paying for “all new power delivery infrastructure upgrades to service their \ndata centers.”  Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":267,"startToken":104583,"endToken":104942,"text":"Docket No. EL25-49-002, et al. \n- 267 - \n3. \nEligible Customer Requirements \na. \nResponse Briefs \n Invenergy requests that the Commission and PJM clarify how the definition of \nEligible Customer applies to Co-Located Generators and Co-Located Loads.1160  \nInvenergy explains that, where a state retail choice program results in unbundled retail \naccess, customers may take transmission service as an Eligible Customer, and that \ntherefore, Invenergy believes that a Co-Located Load could qualify as an Eligible \nCustomer in a retail choice jurisdiction.1161  Invenergy seeks clarity as to whether, in the \ncontext of a Co-Location Arrangement, a Co-Located Generator qualifies as an Eligible \nCustomer on behalf of the Co-Located Load, and whether that Co-Located Generator’s \nstatus as an Eligible Customer depends on whether the Co-Location Arrangement is in a \nretail choice jurisdiction. \nb. \nReply Briefs \n NOVEC argues that the Commission should consider a more definitive delineation \nof who may be an Eligible Customer as well as the scope of the Eligible Customer’s \nobligations.  Specifically, NOVEC seeks confirmation that it cannot be required to serve \nas an Eligible Customer serving Co-Located Load unless it agrees to do so.1162 \n NOVEC argues that the Commission cannot require LSEs to modify their retail \nrates to accommodate these new services and undertake the administrative burden of \nbeing an Eligible Customer for a Co-Located Load unless the LSE chooses to do so.  \nFurther, NOVEC contends that it should not be subject to potential liability for the \ntransmission costs, much less penalties for non-compliance with the Tariff’s \nrequirements, if a Co-Located Load for which NOVEC is serving as Eligible Customer \nfails to meet or comply with all applicable provisions.1163 \n Indicated TOs express support for PJM’s decision to retain the existing definition \nof Eligible Customer.  In response to Invenergy’s request for clarification as to how that \ndefinition applies to Co-Located Generators and Co-Located Loads, Indicated TOs argue \nthat it will depend on an individual Co-Located Generator’s specific factual \ncircumstances.  Indicated TOs contend that a Co-Located Generator is unlikely to meet \n \n1160 Invenergy Comments at 6. \n1161 Id. (citing Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,689). \n1162 NOVEC Reply Brief at 5. \n1163 Id. at 7."},{"page":268,"startToken":104942,"endToken":105312,"text":"Docket No. EL25-49-002, et al. \n- 268 - \nthe definition of an Eligible Customer for purposes of obtaining FCD or NFCD \ntransmission service because it is more likely to sell its output directly to the on-site load \nat retail.  Indicated TOs further contend that the ability of Co-Located Load or an entity \nrepresenting the load to qualify as an Eligible Customer would necessarily depend on \nwhether its host jurisdiction has adopted retail choice.1164 \nc. \nDetermination \n With respect to Invenergy’s request, we note the Tariff defines an Eligible \nCustomer as (1) any electric utility or any person generating electric energy for sale for \nresale, but with respect to transmission service that the Commission is prohibited from \nordering by section 212(h) of the FPA, such entity is eligible only if the service is \nprovided pursuant to a state requirement that the Transmission Provider or Transmission \nOwner offer the unbundled transmission service, or pursuant to a voluntary offer of such \nservice by a Transmission Owner or (2) any retail customer taking unbundled \ntransmission service pursuant to a state requirement that the Transmission Provider or a \nTransmission Owner offer the transmission service, or pursuant to a voluntary offer of \nsuch service by a Transmission Owner.1165  A Co-Located Generator may serve as an \nEligible Customer if it meets the requirements of this definition of Eligible Customer. \n We also clarify that nothing in this order or the December Order requires LSEs to \nmodify their retail rates to accommodate the new transmission services.  We require PJM, \nas the transmission provider, to offer these services, but we do not require LSEs to offer \nthem to their retail customers.  In other words, we do not require any LSE to become an \nEligible Customer taking one of the new transmission services on behalf of an Eligible \nLoad. \n4. \nDemand Side Pathways \na. \nResponse Briefs \n Alliance supports converting Options 7 and 8 from PJM’s March 2025 Answer \ninto enforceable tariff language.  Alliance supports strong measurement and verification \nof load reductions from demand response and energy efficiency in order to implement \nOptions 7 and 8.1166 \n \n1164 Indicated TOs Reply Brief at 6-7. \n1165 PJM, Intra-PJM Tariffs, OATT, § I.1 Definitions – E-F (41.0.0).   \n1166 Alliance Response Brief at 5-6."},{"page":269,"startToken":105312,"endToken":105643,"text":"Docket No. EL25-49-002, et al. \n- 269 - \nb. \nDetermination \n Alliance’s comments are essentially an untimely request for rehearing of the \nDecember Order.  Alliance overlooks that the December Order required PJM to create a \nnew interim non-firm transmission service similar to PJM’s Option 7.  As part of our \ndeterminations with respect to the rates, terms, and conditions for Interim NITS, we are \ndirecting PJM to submit a compliance filing to revise its Tariff to implement this new \ntransmission service.  As for PJM’s Option 8, wherein Co-Located Load that is Network \nLoad may participate as a demand response resource, the Commission in the December \nOrder did not direct any changes to PJM’s demand response rules.  We reiterate, as the \nCommission explained in the December Order, there is not sufficient evidence to \nconclude that the existing Tariff is not just and reasonable as it relates to the existing \ndemand response rules.1167  Co-Located Loads that elect to be Network Load may \nparticipate as a demand response resource under PJM’s existing Tariff to the extent that \nthey meet the requirements to participate as such. \n5. \nInterconnection \na. \nResponse Briefs \n AEU/SEIA claim that PJM proposes to require all co-located generators to \nundergo full interconnection studies, including those that have no intention of exporting \npower to the transmission system.1168  AEU/SEIA argue that PJM indisputably requires \nsufficient information about proposed co-located generators to reliably plan and operate \nthe transmission system, but that subjecting non-exporting facilities to full \ninterconnection studies will impose costs, delays, and administrative burden that are \ndisproportionate to the reliability benefits that are achieved.  AEU/SEIA further argue \nthat this would further strain the interconnection queue to the detriment of the PJM region \nand its customers. \nb. \nReply Briefs \n PJM argues that AEU/SEIA improperly assert that PJM should not study all \ninterconnecting generators.1169   \n \n1167 December Order, 193 FERC ¶ 61,217 at P 242. \n1168 AEU/SEIA Response Brief at 15-16 (citing PJM Initial Brief at 82). \n1169 PJM Reply Brief at 58."},{"page":270,"startToken":105643,"endToken":106014,"text":"Docket No. EL25-49-002, et al. \n- 270 - \nc. \nDetermination \n We find that AEU/SEIA’s concerns about interconnection studies for Co-Located \nGenerators are beyond the scope of this paper hearing, which concerns the rates, terms, \nand conditions of new transmission services that Eligible Customers may take on behalf \nof Eligible Loads.  However, we note that the Commission has approved PJM’s proposal \nto comply with the directives of the December Order that, for Interconnection Customers \nseeking to use new generators to serve Co-Located Load:  PJM will consider requests for \ninterconnection service below the full generating capability of the generator, and such \nInterconnection Customers may use existing procedures to accelerate a new service \nrequest if they satisfy the criteria of the Tariff.1170 \n6. \nCo-Location Arrangement with Electric Storage Resource \na. \nResponse Brief \n Joint Co-Location Developers ask that PJM clarify that its transmission service \nrequirements for electric storage charging apply to storage co-located with load, and \nexempt customers from the Maximum Facility Output where the customer’s load shape \nand characteristics are inherently flexible.1171  Joint Co-Location Developers state that \nPJM does not require electric storage resources to take transmission service for charging, \nexcept where the storage charges during the zonal peak hour without being dispatched.  \nJoint Co-Location Developers claim that, in the context of PJM’s proposal to limit NFCD \ntransmission service to 100% of the Maximum Facility Output of the Co-Located \nGenerator, PJM appears to allow the relevant Co-Located Load to take service while the \nco-located electric storage resource charges.  Joint Co-Location Developers maintain that \nPJM should clarify this point in its Tariff to avoid any implication that this activity is \nprohibited.  Joint Co-Location Developers request that PJM clarify that co-located \ncharging loads, like standalone electric storage resources, do not require transmission \nservice unless they charge during the zonal peak hour without being dispatched, and that \nany withdrawals for electric storage charging at the Point of Interconnection for which \ntransmission service is not required do not count toward the Maximum Facility Output.  \nJoint Co-Location Developers request, in the alternative, that PJM remove the Maximum \nFacility Output limit for loads co-located with electric storage resources. \n \n1170 PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 at P 25. \n1171 Joint Co-Location Developers Response Brief at 13-14."},{"page":271,"startToken":106014,"endToken":106371,"text":"Docket No. EL25-49-002, et al. \n- 271 - \nb. \nReply Brief \n PJM argues Joint Co-Location Developers improperly ask the Commission to \nexamine transmission service for charging electric storage resources.1172 \nc. \nDetermination \n To the extent Joint Co-Location Developers ask the Commission to address \ntransmission service for electric storage resources, such request is beyond the scope of \nthis paper hearing, which concerns the rates, terms, and conditions of new transmission \nservices for Eligible Customers on behalf of Eligible Loads.  However, insofar as Joint \nCo-Location Developers raise concerns about PJM’s proposed requirement that an \nEligible Customer electing to take NFCD transmission service “must apply for [NFCD \ntransmission service] equivalent to the megawatt level of the Co-Located Generating \nFacility dedicated to serving the Co-Located Load,” which Joint Co-Location Developers \nrefer to as the Maximum Facility Output limit, we reject PJM’s proposal above.1173 \nThe Commission orders: \n \n(A) \nIn response to the requests for rehearing, the December Order is hereby \nmodified and set aside, in part, as discussed in the body of this order. \n(B) \nThe clarification requests are hereby denied in part and granted in part, as \ndiscussed in the body of this order. \n(C) \nPJM is hereby directed to submit, within 60 days of the date of issuance of \nthis order, a compliance filing with revisions to its Tariff as described in Part IV.B.3. \n(D) \nPJM is hereby directed to submit, within 60 days of the date of issuance of \nthis order, a compliance filing with revisions to its Tariff as described in Part IV.C.1.b.i.  \n(E) \nPJM is hereby directed to submit, within 60 days of the date of issuance of \nthis order, a compliance filing with revisions to its Tariff as described in Part IV.C.1.c.i. \n(F) \nPJM is hereby directed to submit, within 60 days of the date of issuance of \nthis order, a compliance filing as described in Part V. \n(G) \nPJM is hereby directed to submit, within 60 days of the date of issuance of \nthis order, a compliance filing as described in Part VI. \n \n1172 PJM Reply Brief at 59. \n1173 See supra Part VI.A.2."},{"page":272,"startToken":106371,"endToken":106425,"text":"Docket No. EL25-49-002, et al. \n- 272 - \n(H) \nPJM transmission owners are hereby directed to submit, within 60 days of \nthe date of issuance of this order, a compliance filing as described in Part VI.  \nBy the Commission.  Commissioner Chang is concurring with a separate statement  \n \n \n \n  attached. \n \n( S E A L ) \n \n \n \n \n \n \n \n \n \nDebbie-Anne A. Reese, \nSecretary."},{"page":273,"startToken":106425,"endToken":106660,"text":"Docket No. EL25-49-002, et al. \n- 273 - \nAppendix – Tariff Record[s] \n \nPJM Interconnection, L.L.C. \nIntra-PJM Tariffs \n \n• A-B, OATT Definitions -- A - B (24.0.0)  \n \n• L-M-N, OATT Definitions -- L -- M - N (52.0.0) \n \n• 28.1, OATT 28.1 Scope of Service: (2.0.0) \n \n• 29.1, OATT 29.1 Condition Precedent for Receiving Service (4.0.0) \n \n• 29.2, OATT 29.2 Application Procedures: (4.0.0) \n \n• 31.6, OATT 31.6 Annual Load and Resource Information Updates: (4.0.0) \n \n• 34.2, OATT 34.2 Netting of Behind the Meter Generation. (1.0.0) \n \n• 34.3, OATT 34.3 Netting of Non-Retail Behind The Meter Generation (2.0.0) \n \n• 300 B, OATT 300 Definitions B (2.0.0) \n \n• 300 N, OATT 300 Definitions N (3.0.0) \n \n• 400 B, OATT 400 Definitions B (2.0.0) \n \n• 400 N, OATT 400 Definitions N (4.0.0) \n \n• 401, OATT Part VIII.A 401 Applications for Cycle Process Intro (5.0.0) \n \n• 403, OATT Part VIII.B 403 Application Rules (4.0.0) \n \n• IX Subpart A, OATT Part IX Subpart A FORM OF APPLICATION AND \nSTUDIES AGRMT (4.0.0) \n \n• IX.B GIA Appx-Sched, OATT Part IX.B GIA Appendices and Schedules (5.0.0) \n \n• IX.B GIA Schedule O, OATT Part IX.B GIA Schedule O (0.0.0) \n \n• IX Subpart G, OATT Part IX Subpart G FORM OF NECESSARY STUDIES \nAGREEMENT (3.0.0)"},{"page":274,"startToken":106660,"endToken":106694,"text":"Docket No. EL25-49-002, et al. \n- 274 - \n• XI, OATT XI. TRANSMISSION SERVICES FOR CO LOCATED LOADS \n(0.0.0) \n \n• ATTACHMENT F-3A, OATT ATTACHMENT F-3A (0.0.0) \n \n• ATTACHMENT F-4, OATT ATTACHMENT F-4 (0.0.0)"},{"page":275,"startToken":106694,"endToken":106871,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \n \nPJM Interconnection, L.L.C. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nDelmarva Power & Light Company \nDuke Energy Ohio, Inc. \nDuke Energy Kentucky, Inc. \nEast Kentucky Power Cooperative, Inc. \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nJersey Central Power & Light Company \nMid-Atlantic Interstate Transmission, LLC \nNeptune Regional Transmission System, LLC \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nMonongahela Power Company \nThe Potomac Edison Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nThe Dayton Power and Light Company  \nAEP Appalachian Transmission Company, Inc. \nAEP Indiana Michigan Transmission Company, Inc. \nAEP Kentucky Transmission Company, Inc. \nAEP Ohio Transmission Company, Inc. \nAEP West Virginia Transmission Company, Inc. \nAppalachian Power Company \nIndiana Michigan Power Company \nKentucky Power Company \nKingsport Power Company \nOhio Power Company \nWheeling Power Company \nDocket Nos. EL25-49-002 \nEL25-49-000"},{"page":276,"startToken":106871,"endToken":107098,"text":"Docket No. EL25-49-002, et al. \n- 2 - \nDuquesne Light Company \nVirginia Electric and Power Company \nLinden VFT, LLC \nCity of Cleveland, Department of Public Utilities, \nDivision of Cleveland Public Power \nCity of Hamilton, OH \nSouthern Maryland Electric Cooperative, Inc. \nOhio Valley Electric Corporation \nAMP Transmission, LLC \nSilver Run Electric, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nWabash Valley Power Association, Inc. \nKeystone Appalachian Transmission Company \nLarge Loads Co-Located at Generating Facilities  \nConstellation Energy Generation, LLC \nv.  \nPJM Interconnection, L.L.C. \nPJM Interconnection, L.L.C. \n \n \n \n \n \n \n \n \n \n \n \n \n \n \nAD24-11-001 \n \nEL25-20-001 \n(consolidated) \n \n \n \n \nER26-1479-000 \n \n(Issued June 18, 2026) \n \nCHANG, Commissioner, concurring: \n \n \nIn today’s order, the Commission addresses rehearing requests and the paper \nhearing and compliance record regarding the rates, terms, and conditions through which \nCo-Located Loads may take transmission service from the PJM Interconnection, L.L.C. \n(PJM) system.  I write separately to address the Commission’s resolution of the \n“minimum charge” issue raised in my concurrence to the December Order,1 which I \nbelieve provides a reasonable path forward based on the record before us. \n \nIn its December Order, the Commission asked two briefing questions regarding \nestablishing an additional charge for Eligible Customers on behalf of a Co-Located Load \nthat elects not to take any amount of transmission service or only a de minimis amount of \n \n1 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (December Order) \n(Comm’r Chang, concurring)."},{"page":277,"startToken":107098,"endToken":107566,"text":"Docket No. EL25-49-002, et al. \n- 3 - \ntransmission service.2  At that time, I wrote separately to emphasize my concern that the \nimplementation of our rules around the new transmission services could risk cost shifting \nif those loads take little or no transmission service and thereby do not contribute to \npaying for the transmission system costs.  Broadly, I remain vigilant about the impacts on \nconsumers as the Commission continues to respond to new challenges from large and Co-\nLocated Loads.  \n \nIn today’s order, the Commission concludes that the record does not adequately \nsupport either the need for an additional charge at this time, or how such a charge should \nbe calculated and assessed.  In so doing, the Commission acknowledges the complexity \nof (1) documenting the benefits that accrue to Co-Located Loads paying little or no \ntransmission service from the grid, and (2) designing a charge that corresponds to those \nbenefits.   \n \nAs explained in my concurrence to the December Order, because the Commission \ndoes not require a Co-Located Load to take any specific amount of the new transmission \nservices, it creates the possibility that the load could pay little or nothing towards the \ncosts of the transmission system, notwithstanding potential benefits it receives from that \nsystem.  If this fact pattern occurs, particularly on any significant scale, it may result in \nproblematic cost shifts to other transmission customers.  However, if Co-Located Loads \ndo, in fact, take meaningful transmission service via an existing service or one or both of \nthe new contract demand services, they would pay transmission charges that contribute to \nthe recovery of the transmission system’s capital and operations and maintenance costs.  \nTherefore, whether underlying concerns around cost shifting actually manifest will \nultimately depend on how the new transmission services will be used. \n \nSo, today’s order reasonably concludes that insights from concrete experience \nwith the use of these new transmission services will help inform whether further action \nwould be needed to address cost shifting issues.  Given the challenges demonstrated in \nthe record with articulating or documenting the specific benefits associated with being \nsynchronized to the PJM system, and designing a rate (including conditions under which \nand the parties to whom it will be charged) that is commensurate with those benefits, I \nam persuaded that continued monitoring of this issue is appropriate.   \n \nFurthermore, as part of a broader recognition that implementing the new \ntransmission services represents a significant development in PJM, the Commission \ndirects PJM to prepare an annual report that includes critical information about how these \nservices are being requested and used, as well as how loads using the services contribute \ntoward transmission owners’ revenue requirements.3  The annual reports will provide \n \n2 December Order, 193 FERC ¶ 61,217 at P 219, questions 3 and 4. \n3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209, at PP 580-81 (2026)."},{"page":278,"startToken":107566,"endToken":107648,"text":"Docket No. EL25-49-002, et al. \n- 4 - \ninformation that helps the Commission, the states, market participants, and stakeholders \nmonitor the impacts of these new transmission services, including assessing whether the \npotential cost shift concern discussed above and in my prior concurrence actually occurs.  \nIf it does, I stand ready to consider Federal Power Act section 205 filings or section 206 \ncomplaints (including sua sponte action by the Commission) to address those cost shifts. \nFor these reasons, I respectfully concur.  \n \n \n________________________ \nJudy W. Chang \nCommissioner"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":7,"endAt":2828,"startToken":0,"endToken":1868},{"p":7,"at":2828,"title":"A. Rates, Terms, and Conditions for Firm and Non-Firm Contract Demand","method":"printed heading","endPage":7,"endAt":3614,"startToken":1868,"endToken":1907},{"p":7,"at":3614,"title":"B. Additional Charge for Eligible Customers Taking FCD and/or NFCD","method":"printed heading","endPage":8,"endAt":658,"startToken":1907,"endToken":1949},{"p":8,"at":658,"title":"C. Interconnection Requirements and Operational Practices for Necessary Control","method":"printed heading","endPage":8,"endAt":1472,"startToken":1949,"endToken":1982},{"p":8,"at":1472,"title":"D. Penalty Charge or Other Remedial Action for New Transmission Services - 218 -","method":"printed heading","endPage":8,"endAt":3094,"startToken":1982,"endToken":2052},{"p":8,"at":3094,"title":"G. 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