{"document":{"slug":"e-7-pjm-el26-67-000","title":"PJM show cause order","issued":"2026-06-18","docket":"EL26-67-000","filer":"FERC","group":"June 18 orders","kind":"order","file":"docs/orders/e-7-pjm-el26-67-000.pdf","url":"https://www.ferc.gov/media/e-7-el26-67-000","sha256":"f9c747cfb6f16b646556d1149b529b467a402b6a62e7e7f861c583180a0a383f","pages":114,"tokens":41694,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":176,"text":"195 FERC ¶ 61,211 \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.  \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. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAppalachian Power Company \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nDayton Power and Light Company \nDelmarva Power & Light Company \nDuke Energy Kentucky, Inc. \nDuke Energy Ohio, Inc. \nDuquesne Light Company \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nIndiana Michigan Power Company \nJersey Central Power & Light Company \nKentucky Power Company \nKeystone Appalachian Transmission Company \nKingsport Power Company \nLinden VFT, LLC \nMid-Atlantic Interstate Transmission, LLC \nMonongahela Power Company \nNeptune Regional Transmission System, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nOhio Power Company \nOhio Valley Electric Corporation \nOld Dominion Electric Cooperative \nPECO Energy Company \nDocket No. EL26-67-000"},{"page":2,"startToken":176,"endToken":375,"text":"Docket No. EL26-67-000 \n- 2 - \nPPL Electric Utilities Corporation \nThe Potomac Edison Company \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nSilver Run Electric, LLC \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nVirginia Electric and Power Company \nWabash Valley Power Association, Inc. \nWheeling Power Company \n \nORDER INSTITUTING PROCEEDING  \n \nUNDER SECTION 206 OF THE FEDERAL POWER ACT \n \n(Issued June 18, 2026) \n \n \nParagraph Numbers \nI. Background ..................................................................................................................... 6. \nA. Growth of Large and Co-Located Loads and ANOPR ............................................. 6. \nB. Recent Proceedings Addressing Large and Co-Located Loads .............................. 11. \n1. PJM Co-Location Proceedings ............................................................................ 12. \n2. SPP High Impact Large Load Process and High Impact Large Load Generation \nAssessment Processes .............................................................................................. 15. \n3. SPP Conditional High Impact Large Load Service ............................................. 17. \nII. PJM’s Existing Processes ............................................................................................ 19. \nA. Existing Tariff Processes ......................................................................................... 19. \nB. Recent Stakeholder Proceedings in PJM ................................................................. 31. \nIII. Discussion ................................................................................................................... 35. \nA. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 41. \n1. Jurisdiction ........................................................................................................... 44. \n2. Tariff Provisions .................................................................................................. 50. \nB. Cost Shifting Risk Among Transmission Customers .............................................. 66. \n1. Jurisdiction ........................................................................................................... 68. \n2. Additional Cost Transparency ............................................................................. 71. \n3. Cost Recovery Agreements ................................................................................. 77. \nC. Extending New Transmission Services to Eligible Customers Taking Service on \nBehalf of Flexible Large Loads ................................................................................... 85."},{"page":3,"startToken":375,"endToken":410,"text":"Docket No. EL26-67-000 \n- 3 - \nD. Interconnection Customers Serving Electrically Proximate Large Load and Co-\nLocated Load ................................................................................................................ 88. \n1. Jurisdiction ........................................................................................................... 92. \n2. Definitions ........................................................................................................... 94. \n3. Tariff Provisions .................................................................................................. 95. \nE. Informational Report ............................................................................................. 102. \nIV. Briefing Questions .................................................................................................... 105."},{"page":4,"startToken":410,"endToken":882,"text":"Docket No. EL26-67-000 \n- 4 - \n \nOver the past year, the Commission has taken action in numerous dockets1 to \naddress issues related to (a) unprecedented increases in requests for transmission service \nto serve large loads2 and (b) growing interest in the co-location of loads with generating \nfacilities (co-location arrangements3).  Separately, the Secretary of Energy (Secretary) \nreleased an advance notice of proposed rulemaking (ANOPR) in October 2025.  The \nANOPR, issued pursuant to section 403 of the Department of Energy Organization Act,4 \ndirected the Commission to consider taking additional actions to address the addition of \nlarge and co-located loads to the transmission system.5  The records in these proceedings \nillustrate a host of urgent challenges associated with providing the transmission service \nneeded to serve the ongoing influx of large loads while maintaining reliability and \naffordability.  In particular, stakeholders have expressed concerns that large loads are not \nefficiently and appropriately integrated onto the transmission system; have identified a \n \n1 See, e.g., PJM Interconnection, L.L.C., 190 FERC ¶ 61,115 (2025) (PJM Show \nCause Order); PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (PJM                       \nCo-Location Order); Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026) (SPP HILL \nOrder); Sw. Power Pool, Inc., 195 FERC ¶ 61,196 (2026) (SPP CHILLS Order); see also, \ne.g., Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025); Commonwealth Edison \nCo., 194 FERC ¶ 61,181 (2026). \n2 As explained below, it appears that it would be reasonable to define a large load \nas (1) a new commercial or industrial customer, (2) located at a single site behind one or \nmore points of interconnection, (3) that has a peak load of 50 MW or greater, (4) \ninterconnects to the transmission system at a voltage level of greater than 69 kV, and    \n(5) is not part of a co-location arrangement.  See infra P 58. \n3 The PJM Co-Location Order defined co-located load as “configuration [that] \nrefers to end-use customer load that is physically connected to the facilities of an existing \nor planned Customer Facility on the Interconnection Customer’s side of the Point of \nInterconnection to the PJM Transmission System.”  PJM Co-Location Order, 193 FERC \n¶ 61,217 at P 164 (alterations in original).  The PJM Co-Location Order used the term   \nco-location arrangement when referring to both the co-located load and the associated \ngenerator.  Id. P 3. \n4 42 U.S.C. § 7173. \n5 See Interconnection of Large Loads to the Interstate Transmission System, \nAdvance Notice of Proposed Rulemaking, Docket No. RM26-4-000 (Oct. 23, 2025) \n(ANOPR); see also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy, Docket     \nNo. RM26-4-000 (Oct. 23, 2025).  The ANOPR uses the term “hybrid facilities,” which it \nexplains are large loads that “share a point of interconnection with new or existing \ngeneration facilities.”  ANOPR at P 12.  In this order, we use the term co-located load."},{"page":5,"startToken":882,"endToken":1355,"text":"Docket No. EL26-67-000 \n- 5 - \nnumber of unique challenges that large load integration poses for the reliable operation of \nthat system; and have debated how best to ensure that the rates, terms, and conditions of \ntransmission service remain just and reasonable as more and more large loads are \nonboarded onto that system.6  The records in these proceedings likewise present serious \nconcerns about the lack of clarity and consistency in Regional Transmission Organization \nor Independent System Operator (RTO/ISO) tariffs—including with respect to the rates, \nterms, and conditions of service that apply to flexible large loads, co-location \narrangements, load with behind the meter generation, and generating facilities with \nelectrically proximate large load7 or co-located load. \n \nThe findings in several recent Commission proceedings establish the foundations \nof a just and reasonable framework for addressing these concerns and ensuring the \ntimely, efficient, and reliable integration of large and co-located loads onto the \ntransmission system.  For example, Southwest Power Pool, Inc. (SPP) has recently taken \na number of innovative and proactive steps to address the challenges of integrating large \nloads, co-located loads, and/or generation and electrically proximate large load onto the \ntransmission system while ensuring that its tariff remains just and reasonable.8  PJM \nInterconnection, L.L.C. (PJM), through the Commission’s show cause proceedings, is \nalso addressing the rates, terms, and conditions of service that apply to co-location \narrangements and establishing new transmission services that reflect the ability of \nEligible Customers9 taking transmission service on behalf of Eligible Load to limit their \n \n6 Throughout this order we rely on comments and answers filed in response to the \nANOPR in Docket No. RM26-4-000 and all referenced comments in this order were filed \nin that docket, unless otherwise noted.  A full list of commenter names and abbreviations \nis attached to this order as an Appendix.  Additionally, we have relied on the discussions \nheld in the Federal and State Current Issues Collaborative in Docket No. AD24-7-000 \n(NARUC Collaborative).  All entities who wish to participate in this docket, regardless of \nparticipation in the ANOPR proceeding or NARUC Collaborative, should file to \nintervene in Docket No. EL26-67-000. \n7 As explained below, for purposes of this order, an “electrically proximate large \nload” is a large load, as defined in this order, that is sufficiently electrically close to the \ninterconnection customer’s requested point of interconnection, such that the impact on \nthe transmission system of the combination of the generating facility and the load, with \nthe exception of the transmission facilities between the two, will be effectively the same \nas if they were located at the same substation (e.g., large load that is located no more than \ntwo substations away from the generating facility).  See infra P 94. \n8 SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 61,196. \n9 PJM’s Tariff defines an Eligible Customer as:"},{"page":6,"startToken":1355,"endToken":1749,"text":"Docket No. EL26-67-000 \n- 6 - \nwithdrawals from the transmission system under certain conditions.10  PJM has also taken \nsteps attempting to enhance resource adequacy in the region.11  Because the Commission \nis addressing its concerns related to co-located load in the separate and ongoing Federal \nPower Act (FPA) section 20612 proceeding involving PJM, this order is limited to \naddressing the integration of large loads that are not co-located with generation.  While \nwe appreciate the steps PJM has already taken with respect to co-location arrangements, \nwe note that PJM has not yet proposed tariff revisions to address the challenges \nassociated with the integration of large loads. \n \nAs discussed below, we find that PJM’s existing Open Access Transmission Tariff \n(Tariff) appears to be unjust, unreasonable, or unduly discriminatory or preferential.  We \n \n(i) Any electric utility (including any Transmission Owner \nand any power marketer), Federal power marketing agency, \nor any person generating electric energy for sale for resale . . .  \n(ii) Any retail customer taking unbundled transmission \nservice pursuant to a state requirement that the Transmission \nProvider or a Transmission Owner offer the transmission \nservice, or pursuant to a voluntary offer of such service by a \nTransmission Owner, is an Eligible Customer under the \nTariff.  As used in Tariff, Part VIII, Eligible Customer shall \nmean only those Eligible Customers that have submitted an \nApplication and Study Agreement.   \nPJM Interconnection, L.L.C., Intra-PJM Tariffs, OATT, pt. VIII, § 400 \n(Definitions E) (2.0.0) (PJM Tariff). \n10 PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,         \n193 FERC ¶ 61,217, order on reh’g, 195 FERC ¶ 61,209 (2026) (PJM Co-Location \nRehearing Order).  In the PJM Co-Location Rehearing Order, the Commission used the \nterm Eligible Load to refer to co-located load and/or load with Behind the Meter \nGeneration.  PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91.  \n11 PJM Interconnection, L.L.C., 195 FERC ¶ 61,197 (2026) (PJM EIT Order); \nPJM Interconnection, L.L.C., 190 FERC ¶ 61,084, order on reh’g, 192 FERC ¶ 61,085 \n(2025); see also PJM Interconnection, L.L.C., Informational Report, Docket                          \nNo. EL25-49-000, et al. (filed Jan. 20, 2026); PJM Interconnection, L.L.C., Supplemental \nInformational Report, Docket Nos. EL25-49-000, et al. (filed Feb. 23, 2026); PJM \nInterconnection, L.L.C., Second Supplemental Informational Report, Docket                 \nNo. EL25-49-000, et al. (filed Mar. 9, 2026). \n12 16 U.S.C. § 824e."},{"page":7,"startToken":1749,"endToken":2157,"text":"Docket No. EL26-67-000 \n- 7 - \nthus institute a show cause proceeding pursuant to section 206 of the FPA, and we direct \nPJM and the Transmission Owners,13 within 60 days of the date of this order, to either:   \n(1) show cause as to why the Tariff remains just and reasonable and not unduly \ndiscriminatory or preferential without provisions addressing:   \n(a) the application process, study procedures, and ongoing operational \nrequirements that apply to Eligible Customers seeking transmission service \non behalf of large loads;  \n(b) additional transparency concerning the Network Upgrade14 costs to \nprovide transmission service to Eligible Customers on behalf of large loads, \na pro forma cost recovery agreement between PJM, the relevant \ntransmission owner, and Eligible Customer taking transmission service on \nbehalf of the large load to mitigate the risk of cost shifting among \ntransmission customers, and a mechanism to ensure such payments are \nappropriately credited toward transmission owners’ transmission revenue \nrequirements consistent with the Commission’s cost-of-service regulations;   \n(c) transmission services that reflect Eligible Customers taking transmission \nservice on behalf of flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions;15 and \n \n13 Transmission Owners refers to the entities listed in the caption of this order.  We \nrecognize that PJM’s transmission owners include entities that are not subject to the \nCommission’s jurisdiction because they are not public utilities pursuant to section 201(f) \nof the FPA.  See 16 U.S.C. § 824(f); Sw. Power Pool, Inc., 180 FERC ¶ 61,022,                      \nat PP 44-45 (2022).  Accordingly, the Commission has not included AMP Transmission, \nLLC; City of Cleveland, Department of Public Utilities, Division of Cleveland Public \nPower; City of Hamilton, OH; East Kentucky Power Cooperative, Inc.; and Southern \nMaryland Electric Cooperative, Inc. here as Transmission Owners that must respond to \nthis order to show cause.  Nonetheless, the Commission retains the authority to review \neach entity’s formula rates as a component of PJM’s Tariff in an order to show cause \ndirected towards PJM, and PJM must respond to this order regarding the non-public \nutilities’ PJM Tariff provisions on file with the Commission.  See Sw. Power Pool, Inc., \n180 FERC ¶ 61,022 at P 40. \n14 Capitalized terms not otherwise defined herein have the meanings ascribed to \nthem in the Tariff. \n15 As explained below, for purpose of this order, “flexible” large loads are a subset \nof large loads, as used in this order, that are not co-located with generation, but are"},{"page":8,"startToken":2157,"endToken":2529,"text":"Docket No. EL26-67-000 \n- 8 - \n(d) the rates, terms, and conditions of service applicable to interconnection \ncustomers serving electrically proximate large load or co-located load; or  \n(2) explain what changes to the Tariff would remedy the identified concerns if the \nCommission were to determine that the Tariff has in fact become unjust and \nunreasonable or unduly discriminatory or preferential and, therefore, proceeds to \nestablish a replacement Tariff.  \n \nWe are also concerned with PJM’s need to ensure adequate generation to serve \nnew large loads.16  We therefore direct PJM to submit, within 30 days of the date of \nissuance of this order, an informational report on how PJM intends to ensure that \nadequate generation will be available to serve existing and new large loads, as detailed \nlater in this order.   \n \nWe recognize that large loads, including data centers, are actively working with \ntransmission owners and other relevant entities to interconnect to, and to take service \nfrom, the transmission system.  We appreciate that different large loads are currently at \ndifferent stages of that process.  We also understand that large loads and Eligible \nCustomers taking transmission service on behalf of large loads are negotiating, entering \ninto, and/or have executed various agreements related to interconnecting to the \ntransmission system and/or the provision of transmission service.  This proceeding is not \nintended to disrupt existing commercial arrangements, but rather to establish prospective \nreforms.  Accordingly, any Tariff revisions offered by PJM and/or the Transmission \nOwners in response to this proceeding should (a) propose a reasonable implementation \nperiod to ensure minimal disruption to such existing commercial arrangements, and (b) \nallow a reasonable amount of time to finalize ongoing agreements that are nearing \ncompletion as of the date such Tariff provisions are filed with the Commission.  Such \nproposed Tariff revisions should include a reasonable effective date that accommodates \nsuch considerations regarding these existing commercial arrangements. \n \nwilling and able to limit their energy withdrawals from the transmission system under \ncertain conditions.  See infra note 178. \n16 Cf. PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 237-239 (highlighting \nPJM’s ongoing Critical Issue Fast Path stakeholder process to consider proposals to help \nintegrate large load additions without causing resource inadequacy and directing an \ninformational report on the status of those proposals)."},{"page":9,"startToken":2529,"endToken":2945,"text":"Docket No. EL26-67-000 \n- 9 - \nI. \nBackground \nA. \nGrowth of Large and Co-Located Loads and ANOPR \n \nAs the Secretary explained in the ANOPR, electricity demand in the United States \nis expected to grow at an extraordinary pace in the near term, largely due to the rapid \ngrowth of large loads.17  The Secretary highlighted findings from the North American \nElectric Reliability Corporation (NERC) that show that demand growth is now higher \nthan at any point in the past two decades, driven in part by increasing quantities of large \ncommercial and industrial load, most notably data centers, connecting rapidly to the \ntransmission system.18  The Secretary also highlighted NERC’s conclusion that the size \nand speed with which data centers can be connected to the grid present unique challenges \nfor demand forecasting and system planning.  The ANOPR proposed that, in light of the \nunprecedented current and expected growth of large loads seeking to interconnect to the \ntransmission system, the Commission should standardize interconnection procedures and \nagreements for large loads, including those that seek to share a point of interconnection \nwith new or existing generation facilities.19 \n \nOn April 16, 2026, the Commission issued an order regarding its intent to act with \nrespect to the ANOPR docket.20  In that order, the Commission explained that it agreed \nwith the Secretary “that, ‘[i]n light of the unprecedented current and expected growth of \nlarge loads’ such as data centers, there is an urgent need for thoughtful reforms to ensure \nthat large loads are ‘able to connect to the transmission system in a timely, orderly, and \n \n17 ANOPR at 2 (citing U.S. Dep’t of Energy, Resource Adequacy Report: \nEvaluating the Reliability & Security of the United States Electric Grid (July 2025), \nwww.energy.gov/sites/default/files/2025-\n07/DOE%20Final%20EO%20Report%20%28FINAL%20JULY%207%29.pdf). \n18 Id. (citing NERC, 2024 Long- Term Reliability Assessment 8 (Dec. 2024, \nupdated July 2025), \nhttps://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Long%2\n0Term%20Reliability%20Assessment_2024.pdf). \n19 Id. P 12.  For example, the ANOPR proposed that load and hybrid facilities \nshould be studied together with generating facilities, observing that “siting a large load \nnear or at the same point of interconnection as a new generating facility could reduce the \nnetwork upgrades needed to interconnect only the load or only the generating facility.”  \nANOPR at P 20. \n20 Interconnection of Large Loads to the Interstate Transmission Sys., 195 FERC    \n¶ 61,045 (2026) (Order Regarding Intent to Act)."},{"page":10,"startToken":2945,"endToken":3330,"text":"Docket No. EL26-67-000 \n- 10 - \nnon-discriminatory manner.’”21  After recognizing the Commission’s recent actions in \nproceedings involving issues associated with large loads,22 the Commission concluded \nthat it was clear that additional “action is warranted to support further progress where it is \nneeded.”23 \n \nPJM’s load forecast predicts peak load growth of 32 gigawatts (GW) from 2024 to \n2030, 30 GW of which is projected to be from data centers.24  Many commenters in the \nANOPR proceeding highlight the unprecedented load growth in PJM associated with \nlarge loads.  For example, AES Ohio currently forecasts over 6.3 GW of new load by \n2032, which will nearly triple AES Ohio’s current peak.25  Exelon states that, in \nComEd’s service territory, data center demand has grown at an annual rate of 27% \nthrough                June 2025, and ComEd’s most recent large load adjustment request to \nPJM included a future expected demand increase of 11 GW by 2040, 6 GW higher than \nComEd’s submission relative to the prior year.26  WATT and Advancing Modern \nPowerlines note that PJM is expected to host as much as 70% of future U.S. data center \ndevelopment and that this concentration of demand, especially in northern Virginia’s \n“data center alley,” is creating intense pressure for new greenfield transmission to support \n \n21 Id. P 2. \n22 Id. (citing PJM Co-Location Order, 193 FERC ¶ 61,217; SPP HILL Order,               \n194 FERC ¶ 61,031; Commonwealth Edison Co., 194 FERC ¶ 61,181; Tri-State \nGeneration & Transmission Ass’n, 193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, \nLLC, 193 FERC ¶ 61,237). \n23 Id. PP 3-4. \n24 Letter from David E. Mills, PJM Board of Managers Chair, PJM, \nInterconnection, L.L.C. to PJM Stakeholders (Aug. 8, 2025), https://www.pjm.com/-\n/media/DotCom/about-pjm/who-we-are/public-disclosures/2025/20250808-pjm-board-\nletter-re-implementation-of-critical-issue-fast-path-process-for-large-load-additions.pdf \n(PJM Board Letter).  Since the issuance of the PJM Board Letter, PJM has published its \n2026 Long-Term Load Forecast Report, which anticipates lower peak demand in the near \nterm due to forecasting improvements, revising the peak load forecast for 2030 \ndownward by 875 MW, but confirms significant growth in the next 20 years.  PJM, \nPJM’s Updated 20-Year Forecast Continues to See Significant Long-Term Load Growth \n(Jan. 14, 2026), https://insidelines.pjm.com/pjms-updated-20-year-forecast-continues-to-\nsee-significant-long-term-load-growth/. \n25 AES November 21 ANOPR Comments at 4. \n26 Exelon November 21 ANOPR Comments at 2."},{"page":11,"startToken":3330,"endToken":3751,"text":"Docket No. EL26-67-000 \n- 11 - \nthe interconnection of data centers.27  Buckeye states that load growth of approximately \n10 GW driven largely by data centers in the Dominion Zone of PJM resulted in \napproximately                     $12 billion in transmission investment across PJM.28   \n \nA number of commenters in the ANOPR proceeding assert that large load \nadditions have caused growing resource adequacy, reliability, and affordability problems \nin PJM.29  Commenters also argue that large load interconnection in PJM is experiencing \nsignificant delays.30  In addition, Buckeye and Southeast PIOs express concern that \ninfrastructure costs driven by data center loads will be borne by all transmission \ncustomers in the corresponding PJM transmission zones and, where applicable, in the \nbroader PJM region.31  They and other commenters argue that wholesale transmission \ncustomers are at risk of absorbing cost shifts and that retail large load tariffs do not \nprotect wholesale transmission customers from cost shifting.32  Vistra also raises \nconcerns that PJM and transmission owners’ processes for determining Network \n \n27 WATT and Advancing Modern Powerlines November 21 ANOPR Comments    \nat 4. \n28 Buckeye November 21 ANOPR Comments at 6. \n29 See, e.g., ECA November 21 ANOPR Comments at 8; Geronimo November 21 \nANOPR Comments at 7; Illinois AG November 21 ANOPR Comments at 5-6; Joint \nConsumer Advocates November 21 ANOPR Comments at 2; OCC November 21 \nANOPR Comments at 6-7; PIOs November 21 ANOPR Comments at 3-5, 13-14; PJM \nIMM November 25 ANOPR Comments, Attach. A at 3-5.  \n30 International Energy Credit Association November 21 ANOPR Comments at 6; \nConstellation November 21 ANOPR Comments at 2, 49-51. \n31 See, e.g., Buckeye November 21 ANOPR Comments at 8; Southeast PIOs \nNovember 21 ANOPR Comments at 10-11 (asserting that there is a significant overlap \nbetween multi-driver projects that may be driven by increased loads, including data \ncenters, and those transmission projects selected in PJM’s recent RTEP solicitation). \n32 See, e.g., APPA November 21 ANOPR Comments at 6 (“Wholesale \ntransmission customers in particular could be left shouldering massive costs if new large \nloads do not ultimately attain or maintain the level of electricity demand that is being \nforecasted.”); NRECA November 21 ANOPR Comments at 21 (noting the risk that other \ntransmission customers could bear stranded upgrade costs caused by large loads that they \ncannot absorb); TAPS November 21 ANOPR Comments at 26 (“[A] number of state \ncommissions are moving forward with retail large load tariffs, which provide for varying \nprotections, but may not require the revenues and minimum demand levels to be included \nin wholesale transmission rates.”)."},{"page":12,"startToken":3751,"endToken":4166,"text":"Docket No. EL26-67-000 \n- 12 - \nUpgrades are not included in the Tariff and that existing transmission customers may be \ndisproportionately shouldering the costs for interconnecting large loads.33  OCC requests \nthat the Commission provide additional transparency regarding large load additions.34  \nCommenters also support reforms to capture the efficiencies of generation paired with \nelectrically proximate large load.35 \n \nMoreover, many commenters in the ANOPR proceeding filed persuasive \ncomments documenting, generally, the need for clear and consistent tariff provisions to \nensure regulatory and process certainty, fairness and consistency, and efficiency as large \nloads are added to the transmission system in increasing numbers.36  There is also broad \nsupport for rules that help to ensure that other transmission customers are not unfairly \nburdened with additional costs or reliability impacts as large loads interconnect to the \ntransmission system.37  In addition, many ANOPR commenters highlighted the need to \n \n33 Vistra November 21 ANOPR Comments at 22-23. \n34 OCC November 21 ANOPR Comments at 3-4. \n35 See, e.g., AEP December 5 ANOPR Comments at 10-12; Exelon November 21 \nANOPR Comments at 14; Illinois AG November 21 ANOPR Comments at 8. \n36 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nCalibrant November 21 ANOPR Comments at 1-3; CEBA November 21 ANOPR \nComments at 9-11; Constellation November 21 ANOPR Comments at 6; DCC   \nNovember 21 ANOPR Comments at 3-4; ECA November 21 ANOPR Comments                \nat 7-11; EPSA November 21 ANOPR Comments at 4-6; Infrastructure Masons  \nDecember 5 ANOPR Comments at 4-7; Microsoft November 21 ANOPR Comments          \nat 9-10; National Grid November 21 ANOPR Comments at 7; ODEC December 5 \nANOPR Comments at 2-4; R Street November 21 ANOPR Comments at 3; Switch \nDecember 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments at 5; \nVantage November 21 ANOPR Comments at 5-6; Vistra December 5 ANOPR \nComments at 1-2. \n37 See, e.g., APPA November 21 ANOPR Comments at 6; Buckeye November 21 \nANOPR Comments at 17; Exelon November 21 ANOPR Comments at 10; Kansas \nCommission November 21 ANOPR Comments at 12; NCSL November 21 ANOPR \nComments at 1; NRECA November 21 ANOPR Comments at 8-9; NY UIU                 \nNovember 21 ANOPR Comments at 3; OCC November 21 ANOPR Comments at 9; \nOklo December 5 ANOPR Comments at 3; Southeast PIOs December 5 ANOPR \nComments 11-15; State Entities November 21 ANOPR Comments at 7-8; Tri-State \nNovember 21 ANOPR Comments at 8; UCS November 21 ANOPR Comments at 9-11; \nU.S. Representatives November 21 ANOPR Comments at 1."},{"page":13,"startToken":4166,"endToken":4556,"text":"Docket No. EL26-67-000 \n- 13 - \nefficiently integrate large loads, particularly data centers, to support national security \npriorities and economic development.38    \nB. \nRecent Proceedings Addressing Large and Co-Located Loads \n \nOver the past year, the Commission has begun to address, both sua sponte and in \nresponse to complaints and FPA section 20539 filings, the growing use of co-location \narrangements.40  The Commission’s orders in those proceedings have addressed the need \nfor clear and consistent tariff provisions regarding the rates, terms, and conditions of \nservice that apply to co-location arrangements and for transmission services that reflect \nEligible Customers taking transmission service on behalf of co-located loads and load \nwith behind the meter generation that are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions.  Several other \nCommission proceedings have addressed the challenges of integrating large loads onto \nthe transmission system, including the need for clear and consistent tariff provisions \nregarding the provision of transmission service to Eligible Customers on behalf of large \nloads and for interconnection customers serving electrically proximate large load.  As \nexplained below, these proceedings provide examples that will help to ensure that \njurisdictional transmission service is provided in a manner that is just and reasonable and \nmaintains reliability as large loads are integrated onto the transmission system and                  \nco-location arrangements become more common.  It is in this context, and in recognition \nof the steps PJM has taken with respect to co-location arrangements, that the Commission \nnow considers whether PJM’s Tariff remains just and reasonable. \n1. \nPJM Co-Location Proceedings \n \nOn February 20, 2025, the Commission initiated a show cause proceeding against \nPJM and the PJM Transmission Owners regarding the lack of tariff provisions addressing \nwith sufficient clarity or consistency the rates, terms, and conditions of service that apply \n \n38 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nDCC November 21 ANOPR Comments at 3; ECA November 21 ANOPR Comments             \nat 6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR \nComments at 2-3; Verrus December 5 ANOPR Comments at 2. \n39 16 U.S.C. § 824d. \n40 See PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,                  \n193 FERC ¶ 61,217, order on reh’g, PJM Co-Location Rehearing Order, 195 FERC                 \n¶ 61,209; SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC                      \n¶ 61,196."},{"page":14,"startToken":4556,"endToken":4947,"text":"Docket No. EL26-67-000 \n- 14 - \nto co-location arrangements.41  The Commission explained when initiating that \nproceeding that the absence of such provisions may leave entities unable to determine \nwhat steps they can or must take to effectuate co-location arrangements of various \nconfigurations and how to do so in a manner that is just and reasonable.42  On               \nDecember 18, 2025, the Commission found that PJM’s Tariff was indeed 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 on \nbehalf of co-located load.43   \n \nSpecifically, the Commission found that the PJM Tariff was unjust and \nunreasonable because there is a lack of sufficient clarity or consistency as to the rates, \nterms, and conditions of service that apply to interconnection customers serving                      \nco-located load.44  The Commission also found that PJM’s Tariff was unjust and \nunreasonable because it does not include transmission services that reflect Eligible \nCustomers taking transmission service on behalf of co-located loads that are willing and \nable to limit their energy withdrawals from the transmission system under certain \nconditions.45  Additionally, the Commission found that PJM’s behind the meter \ngeneration rules were no longer just and reasonable.46  The Commission directed PJM to \nfile a compliance filing to revise its Tariff:  (1) to set forth specific terms and conditions \nthat an interconnection customer in PJM seeking to serve co-located load must follow in \norder to effectuate a co-location arrangement;47 (2) to require that the Eligible Customer \ntaking transmission service on behalf of co-located load takes one of three transmission \nservices:  (a) network integration transmission service (NITS) or a new interim, non-firm \ntransmission service while Network Upgrades to provide full NITS service are \n \n41 See PJM Show Cause Order, 190 FERC ¶ 61,115. \n42 Id. P 74.  The PJM Show Cause Order defined co-located load as a \n“configuration [that] refers to end-use customer load that is physically connected to the \nfacilities of an existing or planned Customer Facility on the Interconnection Customer’s \nside of the Point of Interconnection (‘POI’) to the PJM Transmission System.”  Id. P 3 \nn.4.   \n43 PJM Co-Location Order, 193 FERC ¶ 61,217. \n44 Id. P 176.  \n45 Id. P 177. \n46 Id. P 179. \n47 Id. PP 187-192, 225-230."},{"page":15,"startToken":4947,"endToken":5319,"text":"Docket No. EL26-67-000 \n- 15 - \nconstructed (interim NITS); (b) a new firm contract demand transmission service; or (c) a \nnew non-firm contract demand transmission service;48 (3) to revise the behind the meter \ngeneration rules and implement a transition process for existing behind the meter \ngeneration participants;49 and (4) to make several clarifications on how certain aspects of \nPJM’s generator interconnection process apply to interconnection customers seeking to \nserve co-located load.50 \n \nOn June 18, 2026, concurrently with the instant order, the Commission issued an \norder modifying the discussion in the PJM Co-Location Order and setting aside the order \nin part; accepting in part and rejecting in part PJM’s compliance filing, and directing a \nfurther compliance filing; and establishing as just and reasonable certain rates, terms, and \nconditions for the new transmission services (i.e., interim NITS, firm contract demand \ntransmission service, and non-firm contract demand transmission service).51 \n2. \nSPP High Impact Large Load Process and High Impact Large \nLoad Generation Assessment Processes \n \nOn January 14, 2026, the Commission accepted revisions to SPP’s tariff to add a \nhigh impact large load (HILL) study process and High Impact Large Load Generation \nAssessment (HILLGA) process.52  SPP’s tariff revisions established HILLs as a new \ncategory of load;53 imposed enhanced study requirements to enable SPP to assess the \n \n48 Id. PP 193-218.  The Commission also established a paper hearing to determine \nthe just and reasonable rates, terms, and conditions for the new transmission services.  Id. \nPP 219-220. \n49 Id. PP 221-224.  \n50 Id. PP 161, 231-236. \n51 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 7-9.  PJM’s \ncompliance filing proposing revisions in response to the Commission’s directives \nregarding clarification that certain aspects of PJM’s generator interconnection process \napply to interconnection customers seeking to serve co-located load was accepted in part \non April 16, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 (2026). \n52 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64.   \n53 SPP defines a HILL as:   \nA new commercial or industrial load, or increase in \ncommercial or industrial load, at a single site connected \nthrough one or more shared Points of Interconnection (POIs) \nor delivery points, where such load is either:  (1) 10 MW or"},{"page":16,"startToken":5319,"endToken":5719,"text":"Docket No. EL26-67-000 \n- 16 - \nHILL’s reliability impacts on the transmission system;54 and created additional, ongoing \noperational requirements for transmission customers serving HILLs to ensure continued \nreliability of the transmission system.55  The tariff revisions also established the HILLGA \nprocess, a new generator interconnection service and related interconnection process to \nfacilitate the prompt interconnection of generating facilities that are specifically identified \nfor, and limited to, serving a HILL and are located no more than two substations away \nfrom the HILL.56   \n \nmore if connected to the Transmission System at a voltage \nlevel less than or equal to 69 [kilovolts (kV)]; or (2) 50 MW \nor more if connected to the Transmission System at a voltage \nlevel greater than 69 kV.  An Electric Storage Resource is not \nconsidered a HILL.  \nSPP, Open Access Transmission Tariff, Sixth Revised Vol. No. 1, pt. I, § 1                \n(Definitions H) (1.0.0). \n54 SPP HILL Order, 194 FERC ¶ 61,031 at PP 13-17 (explaining that the HILL \nprocess requires up to three additional studies beyond those required of all transmission \nservice requests for transmission customers requesting to add or modify a delivery point \nassociated with a HILL, including a HILL delivery point study, HILL supplemental load \nconnection study, and potential supplemental Electromagnetic Transient study). \n55 Id. P 18 (explaining that market participants registering a HILL must:                       \n(1) follow all nonconforming load requirements (e.g., additional load forecast \nrequirements); (2) provide load data via telemetry in real time; (3) have remote capability \nto disconnect the load from the transmission system made available to the transmission \noperator; (4) have an up/down ramp rate not exceeding 20 MW per minute unless \notherwise directed; (5) include additional information with registration; and (6) not have \nwithdrawals from the transmission system without appropriate transmission service); id. \nP 19 (explaining that the transmission owner, at the transmission customer’s expense, \nmust install a phasor measurement unit or similar equipment); id. PP 20-21 (explaining \nthat the transmission customer will be required to comply with ride-through requirement \nguidelines). \n56 Id. P 27 (explaining that, under the HILLGA process, SPP proposes to study \nHILLGA requests to determine whether any network upgrades are needed to \naccommodate the generating facility’s injection to the local area); id. P 32 (explaining \nthat SPP will grant HILLGA customers a new type of interconnection service, load \nlimited resource interconnection service, which grants limited interconnection service \nsolely to serve the associated HILL)."},{"page":17,"startToken":5719,"endToken":6071,"text":"Docket No. EL26-67-000 \n- 17 - \n \nThe Commission stated that SPP demonstrated that the “unprecedented growth in \nlarge loads in the SPP region presents significant and unique operational and planning \nchallenges.”57  The Commission found that SPP demonstrated that its proposed HILL \nprocess was a just and reasonable approach for integrating transmission customers’ new \nlarge loads onto SPP’s transmission system in a reliable manner.58  The Commission \nfound that it was reasonable to impose additional study requirements and other proposed \nrequirements given the unique operating characteristics of HILLs.  The Commission \nfurther found that the proposed study requirements would ensure the reliable integration \nof the transmission customer’s HILLs onto SPP’s transmission system and would provide \nSPP with information about their impact on SPP’s transmission system, including the \ntransmission system’s ability to withstand and control disturbances by the HILL at the \npoint of interconnection.59  In addition, the Commission found that the proposed study \ndeposits would discourage speculative HILL study requests.60  Finally, the Commission \nconcluded that the proposed ongoing reliability requirements would allow SPP to \nmaintain reliable operation of its transmission system by increasing SPP’s visibility, \nproviding necessary data, and imposing real-time operational safeguards for HILLs.61  In \naccepting HILLGA, the Commission found that “SPP’s HILLGA process reasonably \nprovides a flexible, expedited, and separate serial interconnection process that will \nfacilitate the prompt interconnection of generating facilities that are limited to serving a \nHILL in the same local area.”62   \n3. \nSPP Conditional High Impact Large Load Service \n \nOn June 5, 2026, the Commission accepted revisions to SPP’s tariff to add a new \ntype of non-firm transmission service, conditional high impact large load service \n \n57 Id. P 60. \n58 Id. P 61. \n59 Id. P 62. \n60 For the HILL delivery point study, SPP required a $10,000 non-refundable \napplication fee and a $100,000 study deposit, with an additional $200,000 study deposit if \nan Electromagnetic Transient study was also required.  Id. P 15.  For the HILL \nsupplemental load connection study, SPP allows the host transmission owner to require a \n$25,000 study deposit.  Id. P 16. \n61 Id. P 63. \n62 Id. P 64."},{"page":18,"startToken":6071,"endToken":6375,"text":"Docket No. EL26-67-000 \n- 18 - \n(CHILLS).63  CHILLS allows transmission customers serving HILLs to reliably receive \ntransfers of energy until sufficient designated resources and/or network upgrades are in \nplace to support long-term, firm transmission service.64  CHILLS is an as-available \ntransmission service that will transfer energy to designated points of delivery to serve the \nportion of a HILL eligible to receive CHILLS, subject to curtailment and interruption.65  \nCHILLS has a maximum term of seven years, which is intended to incentivize \ntransmission customers seeking CHILLS to obtain the designated resources and/or \ncomplete the network upgrades needed to procure long-term firm transmission service \nthrough existing tariff processes.66   \n \nThe Commission found that SPP had shown that unprecedented growth in large \nloads presents significant and unique operational and planning challenges.67  The \nCommission also found that SPP’s ability to add HILLs to its transmission system in a \ntimely manner may be limited due to delays in obtaining sufficient designated resources \nand completing network upgrades needed to provide long-term firm transmission service \nto such load.68  The Commission concluded that CHILLS is a just and reasonable and not \nunduly discriminatory or preferential approach to addressing the need to expeditiously \ninterconnect and provide transmission service to new HILLs, while maintaining the \nreliable operation of SPP’s transmission system.69 \nII. \nPJM’s Existing Processes \nA. \nExisting Tariff Processes \n \nPJM’s Tariff sets forth a process by which an Eligible Customer may request \neither NITS,70 including modifications to existing service agreements to add new \n \n63 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. \n64 Id. P 7.  \n65 Id. PP 9-10. \n66 Id. P 9. \n67 Id. P 84. \n68 Id. \n69 Id. \n70 NITS is a transmission service that allows Network Customers to use their \nNetwork Resources (as well as other non-designated generation resources) to serve their"},{"page":19,"startToken":6375,"endToken":6720,"text":"Docket No. EL26-67-000 \n- 19 - \nNetwork Loads, or Point-to-Point Transmission Service.71  In the PJM Co-Location \nOrder, the Commission also directed PJM to create three new transmission services that \nan Eligible Customer taking transmission service on behalf of co-located load may take:  \n(1) an interim, non-firm transmission service until all Network Upgrades necessary to \nprovide the requested NITS are complete, (2) a new Firm Contract Demand transmission \nservice, and (3) a new Non-Firm Contract Demand transmission service.72   \n \nIn PJM, new load additions are processed in one of two ways:  (1) an Eligible \nCustomer requesting new transmission service submits a Transmission Service Request \nto PJM; or (2) for existing Network Customers adding new Network Loads, the Network \nCustomer provides PJM with notice of the designation of new Network Load and must \nmodify its existing service agreement accordingly.73  For NITS and Firm Point-to-Point \nTransmission Service Requests, PJM determines whether a Phase I System Impact \nStudy74 is needed to assess whether the transmission system has sufficient available \ncapability to provide the requested service and tenders an Application and Studies \n \nNetwork Load located in the PJM region and designated additional loads.  PJM Tariff,   \npt. III, § 28.1 (Scope of Service) (1.0.0).   \n71 Point-to-Point Transmission Service provides for “the reservation and \ntransmission of capacity and energy on either a firm or non-firm basis from the Point(s) \nof Receipt to the Point(s) of Delivery.”  Id. pt. I, § 1 (Definitions O-P-Q) (36.0.0) \n(definition of Point-to-Point Transmission Service). \n72 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 160. \n73 PJM Tariff, pt. III, § 31.2 (New Network Loads Connected With the \nTransmission Provider) (1.0.0).  To the extent that a Network Customer seeks to add a \nnew Delivery Point or interconnection point between the PJM transmission system and a \nNetwork Load, the Network Customer must provide PJM with as much advance notice as \nreasonably practicable.  Id. pt. III, § 31.4 (New Interconnection Points) (0.0.0). \n74 PJM’s study process for New Service Requests consists of Phase I, II, and III \nSystem Impact Studies."},{"page":20,"startToken":6720,"endToken":7216,"text":"Docket No. EL26-67-000 \n- 20 - \nAgreement75 to initiate a New Service Request pursuant to which the Eligible Customer \nagrees to reimburse PJM for the required Phase I System Impact Study.76   \n \nPJM studies all New Service Requests including generator interconnection \nrequests, merchant transmission interconnection requests, and long-term firm \ntransmission service requests77 in a single queue (New Services Queue), which is \ngoverned by the transitional interconnection process in Part VII of the Tariff (for requests \nsubmitted between April 1, 2018 and September 30, 2021, where an Interconnection \nCustomer does not have an Interconnection Service Agreement as of July 10, 2023), and \nthe new cycle interconnection process in Part VIII of the Tariff (“new rules” for valid \nNew Service Requests submitted on or after October 1, 2021).78  PJM’s New Services \n \n75 PJM’s Tariff defines an “Application and Studies Agreement” as the application \nthat must be submitted by a Project Developer or Eligible Customer that seeks to initiate \na New Service Request.  PJM Tariff, pt. VII, § 300 (Definitions A) (3.0.0); id. pt. VIII, \n§ 400 (Definitions A) (2.0.0). \n76 Id. pt. III, § 32.1 (Notice of Need for Phase I System Impact Study) (2.0.0); id. \npt. II , § 19.1 (Notice of Need for Phase I System Impact Study) (4.0.0).  As the RTO, \nPJM administers the interconnection of generating facilities and Merchant Transmission \nFacilities, requests for transmission service, and upgrades to existing transmission owner \nfacilities in the PJM transmission system through the New Service Requests process.  \nPJM Manual 14H: New Service Requests Cycle Process, § 1.1 (Sep. 2025), \nhttps://www.pjm.com/-/media/DotCom/documents/manuals/m14h.ashx (PJM                  \nManual 14H). \n77 Id. pt. VII, subpt. C, § 306(A)(3) (Application Rules) (1.1.0) (includes specific \nadditional application requirements for Long-Term Firm Transmission Service seeking to \ninitiate a New Services Request); id. pt. VIII, subpt. B § 403(A)(3) (Application Rules) \n(0.1.0); id., pt. VII, § 300 (Definitions N) (2.0.0) (definition of New Service Request); id. \npt. VIII, § 400 (Definitions N) (2.0.0) (definition of New Service Request); see also id. \npt. VII, § 300 (Definitions C) (2.0.0) (definition of Completed Application); id. pt. VII, \n§ 300 (Definitions I) (2.0.0) (definition of Interconnection Request); id. pt. VIII, § 400 \n(Definitions C) (2.0.0) (definition of Completed Application); id. pt. VIII, § 400 \n(Definitions I) (2.0.0) (definition of Interconnection Request); id. pt. I, § 1                    \n(Definitions A-B) (19.1.1) (definition of Application). \n78 See id. pt. VII, § 301 (Transition Introduction) (1.0.0) (“Part VII sets forth the \nprocedures and other terms governing the Transmission Provider’s administration of the \ntransition to the new Cycle-process, including procedures and other terms regarding \nstudies and other processing of New Service Requests within the Transition Cycle”); id. \npt. VIII, § 401 (Applications for Cycle Process Intro) (2.0.0); id. pt. VIII, § 401(A) (New \nCycle Process) (2.0.0) (“Part VIII of the Tariff applies to valid New Service Requests"},{"page":21,"startToken":7216,"endToken":7704,"text":"Docket No. EL26-67-000 \n- 21 - \nQueue is a first-ready, first-served clustered cycle approach that consists of an application \nphase, a three-phase study process, where each phase includes a System Impact Study \nand decision point, and a final agreement negotiation phase.  For transmission service \nrequests, once the New Service Request is processed, the transmission customer will \nenter into a transmission service agreement, a construction service agreement, and/or a \nNetwork Upgrade cost responsibility agreement.  PJM’s Tariff does not have any specific \nstudy provisions or requirements for Eligible Customers requesting transmission service \non behalf of large load additions.   \n \nThe system impact study is an assessment by PJM of:  (1) the adequacy of the \ntransmission system to accommodate a New Service Request; (2) whether any additional \ncosts may be incurred in order to provide such transmission service or to accommodate a \nNew Service Request; and (3) an estimated date that the New Service Requests can be \ninterconnection with the transmission system and an estimate of the cost responsibility \nfor the interconnection of the New Service Request.79  The System Impact Studies also \nprovide “estimates of cost responsibility and construction lead time for new facilities \nrequired to interconnect the project and required system upgrades,”80 including Network \nUpgrades.  The Tariff describes the phases and studies that determine the cost allocation \nof Network Upgrades to New Service Requests, and PJM Manual 14H provides the \nimplementation details used to govern the interconnection and transmission customers \nservice request process for new generating facilities seeking to connect to or use the PJM \ntransmission system through PJM’s cluster-based queue methodology.81  Specifically, the \n \nsubmitted on or after October 1, 2021, and sets forth the . . . procedures and other terms \nregarding studies and other processing of New Service Requests”); id. pt. VIII, § 401(B) \n(Applications for Cycle Process) (2.0.0) (“Part VIII of the Tariff applies to (a) Generation \nInterconnection Requests; (b) Transmission Interconnection Requests; and (c) Completed \nApplications”). \n79 Id. pt. VIII, § 400 (Definitions S) (3.0.0) (definition of System Impact Study).  \nThe System Impact Study includes facilities study analysis.  \n80 Id. pt. VII, subpt. D, § 307 (Introduction) (1.0.0); id. pt. VII, subpt. D, \n§ 307(A)(2)(a)(ii) (Overview of System Impact Studies) (1.0.0); id. pt. VIII, subpt. C, \n§ 404 (Introduction) (1.0.0); id. pt. VIII, subpt. C, § 404(2)(a)(ii) (Introduction) (1.0.0). \n81 See id. pt. VII, subpt. D § 307 (Introduction) (1.0.0) (including a description of \nthe phases and an overview of the System Impact Studies and cost allocation of Network \nUpgrades, noting that the cost allocation will be in accordance with PJM Manuals); id. pt. \nVII, subpt. D § 307(A)(5)(c) (Cost Allocation for Network Upgrades) (1.0.0); id. pt. VIII, \nsubpt. C, § 404 (Introduction) (1.0.0), id. pt. VIII, subpt. C, § 404(A)(5)(c) (Cost \nAllocation for Network Upgrades) (1.0.0); see PJM Manual 14H: New Service Requests"},{"page":22,"startToken":7704,"endToken":8085,"text":"Docket No. EL26-67-000 \n- 22 - \nTariff provides that each “Eligible Customer shall be obligated to pay for 100% of the \ncosts of the minimum amount of Network Upgrades necessary to accommodate its New \nService Request and that would not have been incurred under the Regional Transmission \nExpansion Plan [(RTEP)] but for such New Service Request, net of benefits resulting \nfrom the construction of the upgrades, such costs not to be less than zero.”82  The Tariff \nfurther specifies that “[a]ll New Service Requests that contribute to the need for a \nNetwork Upgrade will receive cost allocation for that upgrade pursuant to each New \nService Request’s contribution to the reliability violation identified on the transmission \nsystem in accordance with PJM Manuals.”83 \n \nAs relevant on the generator interconnection side, pursuant to the Tariff, a Project \nDeveloper may request, and PJM may provide, Provisional Interconnection Service for \nlimited interconnection service at the discretion of PJM based upon an evaluation that \nwill consider the results of available studies.84  PJM determines, through available studies \nor additional studies as necessary, “whether stability, short circuit, thermal, and/or \nvoltage issues would arise” if the Project Developer interconnects without modifications \nto the Generating Facility or the transmission system.85  Under the Tariff, a Project \nDeveloper may also request surplus interconnection service for an unneeded portion of \ninterconnection service capacity at an existing point of interconnection.86  The surplus \ninterconnection study consists of reactive power, short circuit/fault duty, stability analysis \nand any other appropriate analyses, and steady-state (thermal/voltage) analyses may be \n \nCycle Process, § 4.2.6 (Sep. 2025), https://www.pjm.com/-\n/media/DotCom/documents/manuals/m14h.ashx (PJM Manual 14H). \n82 PJM Tariff, pt. VII, subpt. D, § 307(A)(5)(a) (Cost Allocation for Network \nUpgrades) (1.0.0); id. pt. VIII, subpt. C, § 404 (A)(5)(a) (Cost Allocation for Network \nUpgrades) (1.0.0). \n83 Id. pt. VII, subpt. D, § 307(A)(5)(c) (Cost Allocation for Network Upgrades) \n(1.0.0); id. pt. VIII, subpt. C, § 404 (A)(5)(c) (Cost Allocation for Network Upgrades) \n(1.0.0). \n84 Id. pt. IX, subpt. B, app. 2, § 1.4A.2 (Provisional Interconnection Service) \n(0.0.0). \n85 Id. \n86 Id. pt. VIII, subpt. E, § 414(A) (Surplus Interconnection Service Request) \n(1.0.0)."},{"page":23,"startToken":8085,"endToken":8460,"text":"Docket No. EL26-67-000 \n- 23 - \nperformed as necessary to ensure that all required reliability conditions are studied under \noff-peak conditions.87 \n \nIn PJM, electric distribution companies and transmission owners administer load \ninterconnection processes for existing Network Customers, and transmission owners \nperform local transmission planning to accommodate load additions.88  PJM, as \ntransmission provider, conducts additional studies and transmission planning activities to \nsupport load additions.  Requests to physically interconnect loads are submitted to \ntransmission owners, who have their own study processes and requirements.  Some \ntransmission owners have established specific large load interconnection procedures and \nrequirements.89  New loads taking bundled retail service from a transmission owner or \nthat are served subject to state-required retail access programs (Native Load) are studied \nthrough transmission owners’ local transmission planning processes.  Transmission \nowners must designate resources and loads to serve Native Load in the same manner as \nany Eligible Customer.90   \n \nNetwork Upgrades identified in transmission owners’ local transmission planning \nprocess as needed to accommodate load additions are designated as Supplemental \nProjects under Attachment M-3 of PJM’s Tariff.91  Under Attachment M-3, transmission \nowners plan for the local transmission needs of their own transmission systems.  \nAttachment M-3 provides procedures for stakeholder review and comment on \nSupplemental Projects in the Transmission Expansion Advisory Committee (230 kV or \nabove) and Subregional RTEP Committee (below 230 kV) and as part of a transmission \n \n87 Id. pt. VIII, subpt. E, § 414(B)(1) (Surplus Interconnection Study) (1.0.0). \n88 See PJM November 21 ANOPR Comments at 6. \n89 See, e.g., EEI March 12 ANOPR Comments at 13 (“In December 2025, Exelon \nsubsidiary Delmarva Power submitted proposed changes in line with the Commission’s \nNovember 2025 order: a new service class ‘GS-LD’ applicable to large demand \ncustomers with a monthly maximum of 25 MW or greater.  The company also proposed \nimplementing an application process and specific requirements for potential customers \nwith a projected load of at least 50 MW.”); id. (“Exelon subsidiary Commonwealth \nEdison Company (ComEd) has proposed revisions to Rider DE that clarify requirements \nand procedures for large load customers' new service requests.”).   \n90 PJM Tariff, pt. III, § 28.2 (Transmission Provider Responsibilities) (1.0.0). \n91 See id. attach. M-3 (Additional Procedures for Planning Supplemental Projects \nand Asset Management Projects) (1.0.0)."},{"page":24,"startToken":8460,"endToken":8880,"text":"Docket No. EL26-67-000 \n- 24 - \nowner’s Local Plan, before the Local Plan is submitted for integration into the RTEP.92  \nThese transmission projects do not qualify for region-wide cost allocation, and PJM \nconducts only a “do no harm” test to ensure that local transmission facilities do not \nadversely impact the reliability of the broader transmission system before the \nSupplemental Projects are added into the RTEP base case.93  Supplemental Project costs \nare allocated to the local transmission owner’s zone pursuant to individual transmission \nowner cost allocation frameworks.94    \n \nAttachment H of the PJM Tariff includes the formula rate for each transmission \nowner.  The formula rate calculates the annual transmission revenue requirement, and \nresulting NITS rate, in the relevant PJM transmission zones.  The demand charges for \nNITS, which are charged to the relevant Network Customer (i.e., the Eligible Customer), \nare determined by multiplying the rate for NITS (based on the NITS rate in Attachment H \nof the relevant transmission zone) by the customer’s coincident peak demand.95   \n \nIn some instances, an aggregation of large loads, coupled with other drivers, could \ntrigger regional (as opposed to local) transmission system needs, which would be \nidentified and addressed by a regional transmission project in the RTEP, which is subject \nto PJM’s regional cost allocation method.  For example, a transmission owner may \nidentify a local transmission need that may be more efficiently or cost-effectively \naddressed by a regional transmission project identified in the RTEP.96   \n \nThe Tariff includes a hybrid cost allocation method that was accepted as part of \nPJM’s compliance with Order No. 1000 for Regional Facilities and Necessary Lower \nVoltage Facilities that address a reliability need.97  Under this method, PJM allocates \n \n92 See id. § (c) (Procedures for Review of Attachment M-3 Projects). \n93 See PJM Interconnection, L.L.C., Answer, Docket No. EL25-49-000, at 6-7 \n(filed Mar. 24, 2025); PJM Manual 14B: PJM Regional Transmission Planning Process,    \n§ 1.1 (Apr. 2026), https://www.pjm.com/-\n/media/DotCom/documents/manuals/m14b.pdf#page=14. \n94 PJM Interconnection, L.L.C., Answer, Docket No. EL25-49-000, at 7 (filed \nMar. 24, 2025).    \n95 PJM Tariff, pt. III, § 34.1 (Monthly Demand Charge) (1.0.0). \n96 See, e.g., Potomac Edison Co., 190 FERC ¶ 61,074, at PP 5, 22 (2025) \n(allowing for recovery of abandoned plant costs where a local transmission project was \nsuperseded by regional transmission development in PJM’s RTEP process). \n97 PJM identifies reliability transmission needs and economic constraints that \nresult from the incorporation of public policy requirements into its sensitivity analyses"},{"page":25,"startToken":8880,"endToken":9322,"text":"Docket No. EL26-67-000 \n- 25 - \n50% of the costs of Regional Facilities or Necessary Lower Voltage Facilities on a              \nload-ratio share basis and the other 50% based on the solution-based distribution factor \n(DFAX) method.  PJM allocates all of the costs of Lower Voltage Facilities using the \nsolution-based DFAX method.  Cost responsibility assignments pursuant to the Order   \nNo. 1000-compliant cost allocation method are included in Schedule 12-Appendix A of \nthe Tariff.     \n \nSchedule 12 of the Tariff provides that cost responsibility for the portion of costs \nallocated on a load-ratio share basis will be updated annually using the applicable zonal \nloads at the time of each zone’s annual peak load from the 12-month period ending \nOctober 31 of the calendar year preceding the calendar year for which the annual cost \nresponsibility assignment is determined, consistent with section 34.1 of the Tariff.98  \n \nSchedule 12 of the Tariff also provides that, for the portion of cost responsibility \nassignments allocated pursuant to the solution-based DFAX method, PJM shall make a \npreliminary cost responsibility assignment for each Required Transmission Enhancement \nat the time such transmission facility is selected in the RTEP for purposes of cost \nallocation.  Further, beginning with the calendar year in which a transmission facility is \nscheduled to enter service, and thereafter annually at the beginning of each calendar year, \nPJM shall update the preliminary cost responsibility assignment for each transmission \nfacility using the values and inputs used in the base case of the most recent RTEP \napproved by the PJM Board prior to the date of the update.99  \nB. \nRecent Stakeholder Proceedings in PJM \n \nPJM has begun considering reforms to address large load additions, including the \ndevelopment of solutions to ensure large load additions can continue to be integrated \n \nand allocates the costs of the solutions to such transmission needs in accordance with the \ntype of benefits they provide.  PJM Interconnection, L.L.C., 142 FERC ¶ 61,214, at P 441 \n(2013); see PJM Tariff, Schedule 12 (15.0.0), § (b)(v) (assigning cost responsibility for \nEconomic Projects that are either accelerations or modifications of Reliability Projects, or \nnew enhancements or expansions that relieve one or more economic constraints); PJM, \nIntra-PJM Tariffs, Operating Agreement, Schedule 6, § 1.5 (Procedure for Development \nof the Regional Transmission Expansion Plan) (29.1.0), 1.5.7(c)(iii).  \n98 PJM Tariff, Schedule 12, § (b)(i)(A)(1) (Designation of Customers Subject to \nTransmission Enhancement Charges) (15.0.0). \n99 Id. § (b)(iii)(H)(2) (Designation of Customers Subject to Transmission \nEnhancement Charges) (15.0.0).  The annual update includes any projects that were \nincluded to address any individual transmission owner Form No. 715 local planning \ncriteria."},{"page":26,"startToken":9322,"endToken":9746,"text":"Docket No. EL26-67-000 \n- 26 - \nrapidly and reliably without causing resource inadequacy.  On January 16, 2026, the PJM \nBoard issued a decisional letter on the Critical Issues Fast Path (CIFP) detailing the \ninitiatives that PJM will move forward to implement, which include:  (1) a definition for \nlarge load additions; (2) load forecasting improvements; (3) voluntary “Bring Your Own \nNew Generation” commensurate with large load additions; (4) an expedited generator \ninterconnection track to offset large loads; (5) requiring, in specific circumstances, some \nnew large loads to be subject to curtailment prior to the deployment of pre-emergency \ndemand response pursuant to a “connect and manage” framework; (6) immediate \ninitiation of reliability backstop procurement; (7) holistic review of investment incentives \nin PJM’s energy, reserve, and capacity markets; and (8) feedback on whether to extend \nthe price collar for the 2028/2029 and 2029/2030 capacity auctions.100   \n \nAdditionally, on January 16, 2026, governors from each of the 13 states in PJM \nmet with the White House National Energy Dominance Council and issued a statement of \nprinciples calling on PJM to:  (1) provide 15-year price certainty for new capacity \nresources by holding a reliability backstop auction to procure new capacity resources \ncommencing no later than September 2026; (2) allocate the costs of capacity procured \nthrough the reliability backstop auction to load serving entities with new data centers that \nhave not self-procured new capacity or agreed to be curtailable; (3) extend the existing \nprice collar to the next two Base Residual Auctions; (4) refine load forecasting \nmethodologies by improving large load modeling assumptions; (5) accelerate ongoing \ngenerator interconnection studies; and (6) embark on a stakeholder process to reform the \ncapacity market to ensure long-term viability.101   \n \nIn response, PJM has initiated stakeholder processes on several items.  The PJM \nBoard initiated a new CIFP stakeholder process to engage stakeholders in the \n \n100 PJM, Board Decisional Letter on Critical Issue Fast Path - Large Load \nAdditions (Jan. 16, 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-\nare/public-disclosures/2026/20260116-pjm-board-letter-re-results-of-the-cifp-process-\nlarge-load-additions.pdf.  PJM has since submitted its proposal to extend the price collar \nfor the 2028/2029 and 2029/2030 delivery years, which the Commission accepted on \nApril 28, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,076 (2026).  PJM has also \nsince submitted its proposal for a temporary, expedited generator interconnection process \n(Expedited Interconnection Track), which the Commission accepted on June 9, 2026.  \nPJM EIT Order, 195 FERC ¶ 61,197.  \n101 U.S. Department of Energy, Statement of Principles Regarding PJM (Jan. 16, \n2026), https://www.energy.gov/documents/statement-principles-regarding-pjm."},{"page":27,"startToken":9746,"endToken":10125,"text":"Docket No. EL26-67-000 \n- 27 - \ndevelopment of a reliability backstop procurement mechanism.102  PJM also developed a \nConnect and Manage Senior Task Force to consider the “connect and manage” \nframework to manage the reliability challenges during the transition period in which new \nload additions are outpacing the additions of new capacity in the PJM \nsystem.103  Following initial stakeholder workshops, the PJM Board decided to expand \nthe scope of the CIFP regarding the reliability backstop procurement mechanism to \ninclude the “connect and manage” framework, given the substantive overlap between the \ntwo proposals.104  PJM expects to develop a comprehensive proposal by the end of June, \nwhich it expects to file with the Commission shortly thereafter, with the goal of procuring \nany shortfall resulting from the upcoming Base Residual Auction through a centralized \nprocurement in September 2026.105  PJM has additionally issued a report examining \nmarket design and investment incentives in light of rising demand, which is driven in part \nby the expansion of large loads, and constrained supply.106  PJM has scheduled a series of \nworkshops through August 2026 to develop recommendations based on the choices \npresented in the report.107 \n \nWhile we are encouraged by PJM’s stakeholder efforts, and by its initial attention \nto the pressing concerns associated with large and co-located loads,108 and to the \n \n102 PJM, Critical Issue Fast Path – Reliability Backstop Procurement, \nhttps://www.pjm.com/committees-and-groups/cifp-rbp.   \n103 PJM, Connect and Manage Senior Task Force, \nhttps://www.pjm.com/committees-and-groups/task-forces/camstf.  \n104 PJM, Third Supplemental Informational Report, Docket No. EL25-49-000,      \net al. (filed May 20, 2026); see also PJM, Critical Issue Fast Path - Reliability Backstop \nProcurement / Connect & Manage, https://www.pjm.com/committees-and-groups/cifp-\nrbp. \n105 PJM, Third Supplemental Informational Report, Docket No. EL25-49-000,      \net al. (filed May 20, 2026). \n106 PJM, Powering Reliability Through Market Design: Addressing Rising \nDemand and Constrained Supply, and Stimulating Investment to Support Durable \nReliability (May 6, 2026), https://www.pjm.com/-/media/DotCom/library/reports-\nnotices/special-reports/2026/20260506-powering-reliability-through-market-design.pdf. \n107 PJM, Powering Reliability Through Market Design Workshops, \nhttps://www.pjm.com/committees-and-groups/workshops/prtmdw. \n108 PJM November 21 ANOPR Comments at 12; see also PJM, Large Load \nAdditions Workshop, at 1 (May 9, 2025), https://www.pjm.com/-\n/media/DotCom/committees-groups/workshops/llaw/2025/20250509/20250509-item-02--"},{"page":28,"startToken":10125,"endToken":10452,"text":"Docket No. EL26-67-000 \n- 28 - \nSecretary’s interest in these issues,109 we are initiating this FPA section 206 proceeding \nin order to ensure that PJM’s ongoing processes generate reforms that are sufficiently \ntimely and comprehensive to address the concerns we today identify.  As such, and as the \nCommission explained in the April Order Regarding Intent to Act, we find that the \nCommission must now take further action to ensure that PJM promptly proposes \nrevisions to ensure that its Tariff remains just and reasonable. \nIII. \nDiscussion \n \nBased on the discussion below, pursuant section 206 of the FPA, we direct PJM \nand the Transmission Owners, within 60 days of the date of this order, to either:   \n(1) show cause as to why the Tariff remains just and reasonable and not unduly \ndiscriminatory or preferential without provisions addressing:   \n(a) the application process, study procedures, and ongoing operational \nrequirements that apply to Eligible Customers seeking transmission service \non behalf of large loads;  \n(b) additional transparency concerning the Network Upgrade costs to \nprovide transmission service to Eligible Customers on behalf of large loads, \na pro forma cost recovery agreement between PJM, the relevant \ntransmission owner and Eligible Customer taking transmission service on \nbehalf of the large load to mitigate the risk of cost shifting among \ntransmission customers, and a mechanism to ensure such payments are \nappropriately credited towards transmission owners’ transmission revenue \nrequirements consistent with the Commission’s cost-of-service regulations;  \n(c) transmission services that reflect Eligible Customers taking transmission \nservice on behalf of flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions; and  \n(d) the rates, terms, and conditions of service applicable to interconnection \ncustomers serving electrically proximate large load or co-located load; or  \n \n-large-load-additions-workshop---presentation.pdf (discussing challenges with reliability \nof connecting large loads); PJM IMM, Planning for Large Load Additions (Jan. 7, 2025), \nhttps://www.monitoringanalytics.com/reports/Presentations/2025/IMM_PC_Large_Load\n_Additions_20250107.pdf. \n109 See supra PP 6-7."},{"page":29,"startToken":10452,"endToken":10928,"text":"Docket No. EL26-67-000 \n- 29 - \n(2) explain what changes to the Tariff would remedy the identified concerns if the \nCommission were to determine that the Tariff has in fact become unjust and \nunreasonable or unduly discriminatory or preferential and, therefore, proceeds to \nestablish a replacement Tariff.   \n \nWe also direct PJM to submit, within 30 days of the date of issuance of this order, \nan informational report on how PJM intends to ensure that adequate generation will be \navailable to serve existing and new large loads.   \n \nInterested entities may respond within 30 days of PJM’s and the Transmission \nOwners’ filings, addressing either or both of: (1) whether the existing Tariff remains just \nand reasonable and not unduly discriminatory or preferential; and (2) if not, what changes \nto the Tariff should be implemented as replacement rates.   \n \nWe recognize that PJM and/or the Transmission Owners (to the extent the matters \naddressed herein implicate aspects of the Tariff over which they have the filing rights) \nmay elect to address some or all of the issues discussed in this order by proposing \nrevisions to the Tariff pursuant to their applicable FPA section 205 filing rights.  We \nstrongly encourage this.  Although both the Secretary’s ANOPR and our own Order \nRegarding Intent to Act expressly recognized (and indeed encouraged) that possibility,110 \nno such filings were received from PJM by the Commission prior to the issuance of this \norder.  Should PJM and/or the Transmission Owners elect to make such filings in \nresponse to this order, those filings should state explicitly that the proposals are being \nsubmitted under FPA section 205.  Should PJM and/or the Transmission Owners submit a \nfiling under FPA section 205, they should also explain which of the Commission’s above \ndirectives their filing addresses and how it resolves them.  Additionally, any such filing \nshould provide a reasoned explanation for how the proposal will avoid disrupting existing \ncommercial arrangements and clearly identify a reasonable effective date that \naccommodates such existing commercial arrangements. \n \nThe Commission will consider requests from PJM and/or the Transmission \nOwners to hold, for up to 90 days, all or certain aspects of this FPA section 206 \nproceeding in abeyance, including the deadline to respond to this order.  Any such \nabeyance, which will begin as of the deadline to respond to this order, would be \nconsidered to provide PJM and the Transmission Owners time while they work through \nthe stakeholder processes to develop FPA section 205 filings to revise the Tariff to \naddress the issues raised in this order.  Requests for a full or partial abeyance111 should be \n \n110 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5. \n111 A partial abeyance may be appropriate to the extent PJM is developing FPA \nsection 205 filings in response to only a subset of the directives in this order.  For any"},{"page":30,"startToken":10928,"endToken":11388,"text":"Docket No. EL26-67-000 \n- 30 - \nsubmitted prior to the deadline to respond to this order, specifically within 45 days of \nissuance of this order, to allow time for the Commission to act on the abeyance request.  \nWe emphasize that we will not grant such abeyances reflexively, that any abeyance will \nbe limited to 90 days, and that we will look with great disfavor toward requests to extend \nthe abeyance period.  We anticipate that successful abeyance requests, if any, will include \nboth (1) a robust description of the content of a potential future filing under FPA              \nsection 205 and (2) a reasoned and specific explanation of when such a filing is expected \nto be made.   \n \nIn cases where, as here, the Commission institutes a section 206 investigation on \nits own motion, section 206(b) of the FPA requires that the Commission establish a \nrefund effective date that is no earlier than the date of the publication by the Commission \nof notice of its intention to initiate such proceeding nor later than five months after the \npublication date.  In such cases, in order to give maximum protection to customers, and \nconsistent with our precedent, we have historically tended to establish the section 206 \nrefund effective date at the earliest date allowed by section 206, and we do so here as \nwell.112  That date is the date of publication of notice of initiation of this proceeding in \nthe Federal Register. \nA. \nTransmission Service to Eligible Customers on Behalf of Large Loads \n \nWe today make a preliminary finding that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks provisions that address, with sufficient clarity and \nconsistency, how PJM and/or the Transmission Owners will timely study (i.e., within             \n60-90 days of receiving the request) the provision of transmission service to Eligible \nCustomers on behalf of large loads.113   \n \nThroughout this order, we use the phrase “the provision of transmission service to \nEligible Customers on behalf of large loads” to encompass the provision of new, \nmodified, or additional jurisdictional transmission service to Eligible Customers on \nbehalf of large loads.  We note that this phrase is not limited to instances where an \nEligible Customer submits an application to request new transmission service.  It also \nincludes instances where an Eligible Customer requests a new or modified point of \n \nremaining directives, we expect a response to this order within the 60-day deadline set \nforth herein.  \n112 See, e.g., Idaho Power Co., 145 FERC ¶ 61,122 (2013); Canal Elec. Co.,                 \n46 FERC ¶ 61,153, order on reh’g, 47 FERC ¶ 61,275 (1989). \n113 As discussed below, our findings here also apply to the study process for \nunbundled retail transmission service requests by end-use large load customers, as \nallowed by state law or voluntary utility rules."},{"page":31,"startToken":11388,"endToken":11817,"text":"Docket No. EL26-67-000 \n- 31 - \ndelivery to serve a large load, where a large load seeks a new or modified delivery point \nas an unbundled retail transmission service customer, or where large loads are otherwise \nincluded in an Eligible Customer’s reported load growth and that Eligible Customer is \ntaking NITS.    \n \nWe direct PJM and the Transmission Owners to the extent the matters addressed \nherein implicate aspects of the Tariff over which they have the filing rights, to explain \nwhether the Tariff remains just and reasonable without an application process, study \nprocedures, and ongoing operational requirements that address the unique characteristics \nand challenges of providing transmission service to Eligible Customers on behalf of large \nloads, or to propose appropriate Tariff revisions.   \n1. \nJurisdiction \n \nAt the outset, we clarify the principles relating to the Commission’s jurisdiction \nover the matters relevant to the integration of large loads onto the transmission system \nand the impacts of large loads on the transmission system.  We recognize that rates, \nterms, and conditions associated with the addition of and service to large loads implicate \nboth federal and state interests.  We also recognize that resolution of issues related to \nlarge load additions will require the involvement of both federal and state actors, \nincluding the Commission, state public utility commissions, and other state and local \nentities.  We are encouraged by efforts made at the state level to address issues related to \nlarge load additions that fall within state jurisdiction.114   \n \nAs discussed below, however, certain aspects of the process for integrating large \nloads onto the transmission system fall squarely within the Commission’s exclusive \njurisdiction.  Specifically, we find that it is within the Commission’s exclusive authority \nto ensure that transmission provider and/or transmission owner tariffs include sufficiently \nclear and consistent provisions governing how transmission service to Eligible Customers \non behalf of large loads interconnecting to the transmission system will be studied, \nincluding whether new or upgraded transmission facilities are necessary to provide the \nrequested transmission service.  The Commission has jurisdiction over the study process \nfor transmission service to both Eligible Customers on behalf of large loads and \nunbundled retail transmission service to end-use large load customers where, pursuant to \nstate law or a public utility’s voluntary offer of such service, the large load is an Eligible \nCustomer under the transmission provider and/or transmission owner tariffs.115 \n \n114 See generally NARUC April 14 ANOPR Comments (highlighting action taken \nby state public utility commissions related to large loads). \n115 Under the pro forma OATT, Eligible Customers include end-use customers \nseeking unbundled retail transmission service, pursuant to state law or public utility’s"},{"page":32,"startToken":11817,"endToken":12244,"text":"Docket No. EL26-67-000 \n- 32 - \n \nThe Commission is a creature of statute and has jurisdiction over only those \nmatters that Congress has given it the authority to regulate.116  That authority includes \njurisdiction over the wholesale sale and transmission of electricity in interstate \ncommerce, including all facilities used for such sale and transmission.117  As relevant \nhere, the Commission must ensure that the rates, charges, and classifications for such \ntransmission of electricity—as well as the practices directly affecting such transmission \nof electricity—are just and reasonable and not unduly discriminatory or preferential.118  \nThe Supreme Court has held that the Commission’s authority over interstate transmission \nis not limited to wholesale transmission service and that the Commission has authority \nover unbundled retail transmission service.119  As part of its transmission authority, the \nCommission has exercised jurisdiction over the terms of certain interconnections to the \ntransmission system as an element of transmission service,120 including the \ninterconnection of wholesale load to the transmission system.121  \n \nAs applied to large load additions to the transmission system, these principles \nmean that the Commission has exclusive jurisdiction over the rates, terms, and conditions \nof interstate transmission service to Eligible Customers on behalf of large loads \nconnecting to the transmission system, and the practices directly affecting the provision \nof such interstate transmission of electricity.  An essential component of providing such \ntransmission service is the process by which the transmission provider and/or \n \nvoluntary offer of such service.  Pro forma OATT, § 1.12 (Definitions – Eligible \nCustomer); see also PJM Tariff pt. VIII, § 400 (Definitions E) (2.0.0). \n116 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). \n117 16 U.S.C. § 824(b)(1). \n118 Id. §§ 824d, 824e; see FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 278 \n(2016) (EPSA) (approving “a common-sense construction of the FPA’s language, \nlimiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the \nwholesale rate’” (cleaned up)).    \n119 New York v. FERC, 535 U.S. 1, 17, 19-20 (2002) (upholding the Commission’s \nexercise of jurisdiction over unbundled retail transmission service). \n120 Tenn. Power Co., 90 FERC ¶ 61,238, at 61,761 (2000) (Tennessee Power), \norder denying reh’g, 91 FERC ¶ 61,271 (2000); Standardization of Generator \nInterconnection Agreements & Procs., Order No. 2003, 104 FERC ¶ 61,103, at P 9 \n(2003); see also Laguna Irrigation Dist., 91 FERC ¶ 61,340, at 62,152 (2000). \n121 Pac. Gas & Elec. Co., 109 FERC ¶ 61,392, at P 37 (2004); Pac. Gas & Elec. \nCo., 115 FERC ¶ 61,193, at PP 36-38 (2006)."},{"page":33,"startToken":12244,"endToken":12665,"text":"Docket No. EL26-67-000 \n- 33 - \ntransmission owner evaluates (1) whether it can provide the requested transmission \nservice and (2) the impact that providing such transmission service will have on the \njurisdictional transmission system, including determining whether any new or upgraded \ntransmission facilities are needed to provide transmission service while maintaining \nreliable operation of the transmission system.  This transmission service study process \ndetermines what Network Upgrades are needed to provide transmission service to \nEligible Customers on behalf of large loads, the costs of which are included in \ntransmission rates.  As such, this study process directly affects Commission-jurisdictional \ntransmission rates.122  The Commission has exclusive authority to ensure that the process \nto study the provision of transmission service to Eligible Customers is just and reasonable \nand not unduly discriminatory or preferential.  We therefore find that we have authority \nto ensure that tariffs include provisions that clearly and consistently address the study \nprocess for the provision of transmission service to Eligible Customers on behalf of large \nloads, including the unique impacts that providing transmission service to Eligible \nCustomers on behalf of large loads may have on the transmission system. \n \nAt the same time, we continue to recognize that the FPA expressly reserves to \nstates the authority over any other sale of electric energy, including retail sales and \nwholesale sales not in interstate commerce (such as wholesale sales within the Electric \nReliability Council of Texas region), as well as facilities used for the generation and \ndistribution of electricity.123  As such, we recognize that states will continue to regulate:  \n(1) the specific terms of retail sales to large load;124 (2) which entities may make retail \nsales within their borders, including which entities are legally permitted to provide \nelectricity to retail large load customers;125 and (3) any siting decisions and construction \n \n122 Cf. Transmission Plan. & Cost Allocation by Transmission Owning & \nOperating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051, at P 112 (2011) (“It is \nthrough the transmission planning process that public utility transmission providers \ndetermine which transmission facilities will more efficiently or cost-effectively meet the \nneeds of the region, the development of which directly impacts the rates, terms and \nconditions of jurisdictional service.”). \n123 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th \n1107, 1129 (6th Cir. 2025). \n124 See EPSA, 577 U.S. at 279-80 (recognizing state authority over retail electricity \nsales); New York v. FERC, 535 U.S. at 28 (same). \n125 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69."},{"page":34,"startToken":12665,"endToken":13131,"text":"Docket No. EL26-67-000 \n- 34 - \nassociated with the large load project.126  Nothing in this order is intended to intrude upon \nstate authority over retail service to large loads.   \n \nIn sum, we today exercise our authority to ensure that the process by which \njurisdictional transmission providers and/or transmission owners will study the provision \nof jurisdictional transmission service to Eligible Customers on behalf of large loads \ninterconnecting to the transmission system, including where, as allowed by state law or a \npublic utility’s voluntary offer of such service, an end-use large load seeks unbundled \nretail transmission service, is just and reasonable and not unduly discriminatory or \npreferential.  Pursuant to that authority, we find that PJM’s Tariff appears to be unjust \nand unreasonable or unduly discriminatory or preferential because it lacks sufficiently \nclear and consistent provisions regarding the study process related to the provision of \ntransmission service to Eligible Customers on behalf of large loads.  We need not \ncomprehensively address the Commission’s jurisdiction over other aspects of the addition \nof large loads to the transmission system at this time.  \n2. \nTariff Provisions \n \nIn the following section, we begin by considering PJM’s Tariff as it relates to how \nPJM and/or the Transmission Owners will study the provision of transmission service to \nEligible Customers on behalf of large loads and explain our concerns that the lack of \nsufficiently clear and consistent provisions regarding the study process for the provision \nof transmission service to Eligible Customers on behalf of large loads is unjust and \nunreasonable or unduly discriminatory or preferential.  We then consider whether the \nTariff is unjust and unreasonable without certain elements.  First, we consider whether \nthe Tariff lacks sufficiently clear and consistent Tariff provisions establishing an \nappropriate definition of large load, as a separate category of load.  Second, we consider \nwhether the Tariff lacks sufficiently clear and consistent Tariff provisions establishing an \napplication process and requirements for Eligible Customers requesting transmission \nservice on behalf of large loads and a study process that considers the unique operational \nchallenges of providing transmission service to Eligible Customers on behalf of large \nloads.  Third, we consider whether the Tariff lacks sufficiently clear and consistent Tariff \nprovisions establishing ongoing operational requirements necessary to ensure that PJM \ncan reliably provide transmission service given the unique operational impacts on the \ntransmission system of providing transmission service to Eligible Customers on behalf of \nlarge loads.  Finally, we consider whether the Tariff requires such ongoing operational \n \n126 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th 229, 238 (D.C. \nCir. 2025) (citing 16 U.S.C. § 824(b)(1)) (recognizing state authority over generation \nresource mix, including through their siting authority); Order No. 1000, 136 FERC                 \n¶ 61,051 at P 107 (acknowledging state authority over siting, permitting, and construction \nof transmission facilities)."},{"page":35,"startToken":13131,"endToken":13555,"text":"Docket No. EL26-67-000 \n- 35 - \nrequirements for Eligible Customers taking transmission service on behalf of large loads \nto be memorialized in service agreements. \n \nWe preliminarily find that PJM’s Tariff appears to be unjust and unreasonable or \nunduly discriminatory or preferential because it does not contain provisions addressing \nwith sufficient clarity and consistency how PJM and/or the Transmission Owners will \nstudy the provision of transmission service to Eligible Customers on behalf of large \nloads.  We recognize that PJM and/or the Transmission Owners may have existing load \nintegration processes, including studies that are performed in evaluating the provision of \ntransmission service to Eligible Customers on behalf of large loads.127  However, we are \nconcerned that those processes and any required studies with regard to the provision of \ntransmission service are not described in the Tariff with the degree of clarity and \nspecificity necessary to ensure that the transmission provider can mitigate operational \nrisks of providing transmission service to Eligible Customers on behalf of large loads, \ngiven their impact on the transmission system, avoid disputes regarding how studies are \nconducted, deter speculative or duplicative requests for transmission service by Eligible \nCustomers on behalf of large loads, and help avoid excessive and unnecessary Network \nUpgrades.  Moreover, we are concerned that the existing Tariff does not contain other \nelements akin to those described below, which we preliminarily find may be necessary to \nensure that the rates, terms, and conditions of jurisdictional transmission service are just \nand reasonable.   \n \nAt the outset, we recognize that the Transmission Owners may be primarily \nresponsible for conducting the studies that (1) evaluate whether a large load may be \ninterconnected to the transmission system and served by the Eligible Customer, and                \n(2) determine whether Network Upgrades are necessary to provide transmission service.  \nWe appreciate that this role may stem from how PJM and the Transmission Owners \nallocated rights and responsibilities in the governing documents establishing PJM.  We \ndo not seek to alter that allocation of rights and responsibilities. \n \nWe are nonetheless concerned that PJM’s Tariff lacks a study process that \naddresses the unique operational and reliability challenges that providing transmission \nservice to Eligible Customers on behalf of large loads presents to the transmission \nsystem.  Large loads can be more energy intensive and geographically concentrated than \ntraditional load, and exhibit different load profiles and operational characteristics.128  \n \n127 See supra PP 20-24. \n128 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at PP 7-8; NERC, \nCharacteristics and Risks of Emerging Large Loads (July 2025), \nhttps://www.nerc.com/globalassets/who-we-are/standing-committees/rstc/whitepaper-"},{"page":36,"startToken":13555,"endToken":13988,"text":"Docket No. EL26-67-000 \n- 36 - \nPJM itself has recognized that enhanced large load saturation can have a disproportionate \nimpact on system reliability, including voltage and frequency fluctuations due to their \nsize and unique characteristics, if mitigating operational steps and other protection \nschemas are not developed and implemented.129  The PJM Board has also recognized that \nthe scale, pace, and characteristics of large load growth present significant operational \nand planning challenges.130  As a result, providing transmission service to Eligible \nCustomers on behalf of large loads may be more complex and could raise greater \nreliability concerns for the transmission system, relative to a situation where Eligible \nCustomers seek transmission service on behalf of traditional load. \n \nWithout a clear and consistent process to study the provision of transmission \nservice to Eligible Customers on behalf of large loads, PJM and/or the Transmission \nOwners may not fully capture the transmission system impacts of providing such \ntransmission service, which could result in significant operational risks for the \ntransmission system.  Furthermore, we are concerned that, without sufficiently clear and \nconsistent Tariff provisions, PJM will not have the ongoing visibility and operational \ncontrol necessary to provide reliable transmission service. \n \nWe are also concerned that the absence of sufficiently clear and consistent Tariff \nprovisions for how PJM and/or the Transmission Owners will study the provision of \ntransmission service to Eligible Customers on behalf of large loads will lead to disputes \nover a variety of issues—e.g., study timelines and delays,131 how the transmission service \nneeded on behalf of the large load is studied,132 what types of Network Upgrades are \n \ncharacteristics-and-risks-of-emerging-large-loads.pdf (NERC Characteristics and Risks \nof Large Loads). \n129 PJM November 21 ANOPR Comments at 12. \n130 See PJM Board Letter.  PJM TOs further note that many data centers’ initial \nloads are significantly lower when they first enter commercial operation, but following \nexpansion and full potential of operation capacity, their demand increases to much higher \nlevels.  PJM TOs November 21 ANOPR Comments at 9. \n131 See, e.g., Institute for Progress November 21 ANOPR Comments at 7-8; \nMicrosoft November 21 ANOPR Comments at 9; ODEC December 5 ANOPR \nComments at 4; Vistra November 21 ANOPR Comments at 21 (discussing lack of \ndefined load interconnection process in PJM and lack of detail in PJM Tariff and manuals \nregarding load integration study). \n132 Commenters raised concern that large loads are not studied with consideration \nof their known operating characteristics, including their willingness to be flexible or \ncurtailable.  See, e.g., ClearPath November 21 ANOPR Comments at 5-6; Constellation \nNovember 21 ANOPR Comments at 23-24; Critical Loop November 21 ANOPR"},{"page":37,"startToken":13988,"endToken":14443,"text":"Docket No. EL26-67-000 \n- 37 - \nconsidered, and how required Network Upgrades to provide the requested transmission \nservice are determined.133  Such disputes may arise from the lack of transparency in how \nstudies are performed and how decisions will be made.134  We are thus concerned that the \nlack of clear and consistent provisions in PJM’s Tariff related to the study process for the \nprovision of transmission service to Eligible Customers on behalf of large loads appears \nto be unjust and unreasonable or unduly discriminatory or preferential.   \n \nLastly, we are concerned that PJM’s existing Tariff fails to deter speculative or \nduplicative requests for transmission service by Eligible Customers on behalf of large \nloads.  Many ANOPR comments assert that clear and consistent provisions establishing \nstudy timelines and costs, readiness requirements, and/or penalties will deter speculative \nor duplicative requests related to large load additions.135  Commenters explain that \n \nComments at 3; GridCare December 5 ANOPR Comments at 1-2; L. Lynne Kiesling \nNovember 21 ANOPR Comments at 10. \n133 Specifically, commenters raised concern that transmission providers/owners \nmay only consider traditional transmission infrastructure or that there is a lack of \nconsideration of alternative transmission solutions.  See, e.g., ACORE November 21 \nANOPR Comments at 3-4, 6-7; American Terawatt November 21 ANOPR Comments            \nat 4-5; Calibrant November 21 ANOPR Comments at 1-2, 3; CEBA November 21 \nANOPR Comments at 9-10; Chamber of Commerce November 21 ANOPR Comments  \nat 3; CTC Global Corporation November 21 ANOPR Comments at 1-3; DCC            \nNovember 21 ANOPR Comments at 10-11; GridCARE December 5 ANOPR Comments \nat 4; Industrial Customers November 21 ANOPR Comments at 27-28; Infrastructure \nMasons December 5 ANOPR Comments at 18; Iron Mountain Data Centers, LLC \nNovember 21 ANOPR Comments at 3-4; Land Trust Alliance November 21 ANOPR \nComments at 5-6; PIOs November 21 ANOPR Comments at 22; Southeast PIOs \nNovember 21 ANOPR Comments at 44-45; WATT and Advancing Modern Powerlines \nNovember 21 ANOPR Comments at 5-8. \n134 See, e.g., CEBA November 21 ANOPR Comments at 12; ECA December 5 \nANOPR Comments at 1-2; Eolian November 21 ANOPR Comments at 17-18; EPSA \nNovember 21 ANOPR Comments at 6; Infrastructure Masons December 5 ANOPR \nComments at 4, 6-7; Southeast PIOs November 21 ANOPR Comments at 39-40; Switch \nDecember 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments at 5; \nVantage November 21 ANOPR Comments at 5-6; Verrus November 21 ANOPR \nComments at 6, 12; Vistra December 5 ANOPR Comments at 27. \n135 See, e.g., ACORE November 21 ANOPR Comments at 6; AEU November 21 \nANOPR Comments at 17-18; Amazon November 21 ANOPR Comments at 6; Crusoe \nDecember 5 ANOPR Comments at 5-6; EDF Power November 21 ANOPR Comments  \nat 12-13; EEI November 21 ANOPR Comments at 20; Fervo November 21 ANOPR"},{"page":38,"startToken":14443,"endToken":14860,"text":"Docket No. EL26-67-000 \n- 38 - \nspeculative requests may bog down and delay the study process, wasting time and \nresources for transmission providers;136 result in inaccurate study results or delays for \nother Eligible Customers seeking transmission service on behalf of load;137 create a \nsubstantial risk of cost shifts if the large load additions do not materialize as planned;138 \nand distort load forecasts.139  Clear and consistent study procedures that include readiness \nrequirements (i.e., meaningful milestones and/or financial commitments) can help ensure \nthat Eligible Customers’ requests for transmission service on behalf of large loads are \nmore viable and more likely to materialize as planned, given that they must meet specific \nmilestones and/or pay costs to proceed.  \n \nMore specifically, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks sufficiently clear and consistent Tariff provisions that \n \nComments at 3; GridCare December 5 ANOPR Comments at 5; Invenergy November 21 \nANOPR Comments at 6; Microsoft November 21 ANOPR Comments at 9; Ohio FEA \nNovember 21 ANOPR Comments at 4. \n136 See, e.g., Eolian November 21 ANOPR Comments at 17-18; GridCare \nDecember 5 ANOPR Comments at 5; Illinois AG November 21 ANOPR Comments               \nat 9-10; Institute for Progress November 21 ANOPR Comments at 9; OCC November 21 \nANOPR Comments at 7-8; Ohio FEA November 21 ANOPR Comments at 4; Vistra \nNovember 21 ANOPR Comments at 23. \n137 See, e.g., Amazon November 21 ANOPR Comments at 6; CEBA November 21 \nANOPR Comments at 8; ClearPath November 21 ANOPR Comments at 4; Geronimo \nNovember 21 ANOPR Comments at 12; TAPS November 21 ANOPR Comments                    \nat 14-15. \n138 See, e.g., AES November 21 ANOPR Comments at 10-11; Buckeye             \nNovember 21 ANOPR Comments at 1-2; Exelon November 21 ANOPR Comments at 3; \nNRECA November 21 ANOPR Comments at 9; OCC November 21 ANOPR Comments \nat 9; Southeast PIOs November 21 ANOPR Comments at 20; State Entities November 21 \nANOPR Comments at 7-8; TAPS November 21 ANOPR Comments at 15, 22-24;                \nTri-State November 21 ANOPR Comments at 6, 8; Vistra November 21 ANOPR \nComments at 23. \n139 See, e.g., CEBA November 21 ANOPR Comments at 8; EEI November 21 \nANOPR Comments at 20; ELCON November 21 ANOPR Comments at 7; Invenergy \nNovember 21 ANOPR Comments at 6; GridCare December 5 ANOPR Comments at 5; \nOCC November 21 ANOPR Comments at 9; PIOs November 21 ANOPR Comments            \nat 5; Southeast PIOs November 21 ANOPR Comments at 41; Talen November 21 \nANOPR Comments at 9."},{"page":39,"startToken":14860,"endToken":15254,"text":"Docket No. EL26-67-000 \n- 39 - \naddress certain aspects of the process to provide transmission service to Eligible \nCustomers on behalf of large loads, including:    \n(1) a definition of large load sufficient to capture loads that present the unique \nchallenges described herein;  \n(2) the application process for requesting transmission service to Eligible \nCustomers on behalf of large loads and the study procedures, including readiness \nrequirements, for studying the provision of transmission service to Eligible \nCustomers on behalf of large loads;  \n(3) ongoing operational requirements for transmission customers140 serving large \nloads necessary to ensure reliable operation of the transmission system; and  \n(4) pro forma provisions in transmission service agreements to memorialize these \nterms. \n \nFirst, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks a definition of large load, as a new category of load.  As \nPJM acknowledges, integrating large loads poses specific challenges to transmission \nsystem operation given their size, operational behavior, and unique potential to impact \nthe transmission system.141  An appropriate definition, including a load size and \ninterconnection voltage threshold, should be based on the characteristics of PJM’s \ntransmission system.  That said, based on the record in the ANOPR proceeding,142 it \nappears that it would be reasonable to define a large load as a new, commercial or \n \n140 We note that such ongoing operational requirements should apply to \ntransmission customers, rather than Eligible Customers, as these requirements apply after \nthe Eligible Customer has an executed (or a filed unexecuted) service agreement for \ntransmission service and have become transmission customers under the Tariff.  \n141 PJM November 21 ANOPR Comments at 12. \n142 See, e.g., Constellation November 21 ANOPR Comments at 13 (supporting a \nvoltage threshold); DTE November 21 ANOPR Comments at 3, 17-19 (recommending a \nthreshold of an amount between 50 MW to 100 MW); Eolian November 21 ANOPR \nComments at 8-9 (recommending a voltage threshold greater than or equal to an amount \nbetween 60 kV to 100 kV); Illinois AG November 21 ANOPR Comments at 7 \n(supporting a 20 MW or 50 MW threshold and consideration of other factors, such as \nvoltage level); ITC November 21 ANOPR Comments at 3 (recommending a threshold of \nbetween 50 MW to 100 MW); Nebraska Board November 21 ANOPR Comments at 4 \n(proposing a 50 MW threshold); New Mexico Commission November 21 ANOPR \nComments at 5 (proposing a 50 MW threshold)."},{"page":40,"startToken":15254,"endToken":15707,"text":"Docket No. EL26-67-000 \n- 40 - \nindustrial customer, located at a single site behind one or more points of interconnection, \nand that has a peak load of 50 MW or greater, interconnects to the transmission system at \na voltage level of greater than 69 kV, and is not part of a co-location arrangement.  In its \nresponse to this order, PJM should explain whether the Tariff remains just and reasonable \nwithout such a definition, or propose Tariff revisions establishing its own definition of \nlarge load. \n \nSecond, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks sufficiently clear and consistent Tariff provisions \nestablishing the application process and study procedures that will be used when PJM \nand/or the Transmission Owners evaluate the provision of transmission service to \nEligible Customers on behalf of large loads.  PJM should explain whether the Tariff \nremains just and reasonable, for example, without:  (1) an application process that accepts \nEligible Customers’ applications for transmission service on behalf of large loads on a \nrolling basis; (2) a non-refundable application fee and sufficient readiness requirements \nthat escalate at distinct phases of the study process to deter duplicative or speculative \nrequests for transmission service (e.g., meaningful milestones and/or financial \ncommitments); and (3) information and data requirements that Eligible Customers must \nsubmit to PJM and/or the Transmission Owners regarding the characteristics of the large \nload on behalf of which the Eligible Customer is taking transmission service, including \ndisclosure to PJM of any substantially similar pending transmission service requests on \nbehalf of the same large load customer.143  PJM may also elect to propose Tariff revisions \nestablishing such an application process, fee, and requirements.   \n \nFurther, PJM’s Tariff appears to lack sufficiently clear and consistent provisions \nestablishing a study process for evaluating the provision of transmission service to \nEligible Customers on behalf of large loads that considers the unique characteristics and \nimpacts of large loads on the transmission system.  For example, we are concerned that \nPJM’s Tariff may not clearly and consistently require PJM or the Transmission Owners \nto conduct studies that evaluate the transmission system’s ability to withstand risks \nobserved from analyzed large load behavior created by the large load at the point of \ninterconnection, or any other necessary supplemental studies to evaluate the impact of \nproviding transmission service to Eligible Customers on behalf of large loads.144  \n \n143 The Electric Reliability Council of Texas (ERCOT) has proposed a similar \ndisclosure requirement in its Batch Zero process for large load interconnections.  ERCOT \nPlanning Guide, § 9.7.1(1)(b) (proposed Mar. 4, 2026). \n144 See generally NERC, Industry Recommendation:  Large Load Interconnection, \nStudy, Commissioning, and Operations (Sep. 2025), \nhttps://www.nerc.com/globalassets/programs/bpsa/alerts/2025/nerc-alert-level-2--large-"},{"page":41,"startToken":15707,"endToken":16064,"text":"Docket No. EL26-67-000 \n- 41 - \nAdditionally, we preliminarily find that PJM’s Tariff appears unjust and unreasonable \nbecause it lacks appropriate provisions recognizing within the transmission service \nrequest study process the unique operational characteristics of large loads that are willing \nand able to limit their energy withdrawals under certain conditions, which may thereby \nlessen or potentially avoid the need for certain Network Upgrades.  While flexible large \nloads can reduce the demand on the transmission system, and therefore potentially reduce \nthe need for additional transmission capacity, additional informational and study \nrequirements may be necessary to account for the dynamic nature of these types of loads \nwhile maintaining reliability.145  Additionally, we note that accurate models using \nElectromagnetic Transient studies may help to ensure that transmission service needed on \nbehalf of large loads can be provided without compromising reliability.146 \n \nAdditionally, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks clear and consistent provisions requiring the evaluation of \nalternative transmission technologies147 as potential solutions to accommodate an \nEligible Customer’s request for transmission service on behalf of a large load.  \nAlternative transmission technologies can add more capacity on existing transmission \n \nloads.pdf (finding that unique operational characteristics of large loads necessitate \nenhancements to studies). \n145 See, e.g., AEMA November 21 ANOPR Comments at 6; Thermal Battery \nAlliance November 21 ANOPR Comments at 7; Verrus November 21 ANOPR \nComments at 10. \n146 See, e.g., NERC, Draft Reliability Guideline:  Risk Mitigation for Emerging \nLarge Loads 6-7 (May 2026), https://www.nerc.com/globalassets/who-we-are/standing-\ncommittees/rstc/reliabilityguideline_riskmitigationforemerginglargeloads.pdf; NERC, \nAssessment of Gaps in Existing Practices, Requirements, and Reliability Standards for \nEmerging Large Loads 31 (Mar. 2026), https://www.nerc.com/globalassets/our-\nwork/guidelines/reliability/white-paper---assessment-of-gaps.pdf; see also SPP HILL \nOrder, 194 FERC ¶ 61,031 at P 62. \n147 For purposes of this order, alternative transmission technologies include static \nsynchronous compensators, static VAR compensators, advanced power flow control \ndevices, transmission switching, synchronous condensers, voltage source converters, \nadvanced conductors, tower lifting, and dynamic line ratings.  We note that the \nCommission has also referred to these types of technologies as Grid Enhancing \nTechnologies (GETs)."},{"page":42,"startToken":16064,"endToken":16484,"text":"Docket No. EL26-67-000 \n- 42 - \nlines quickly, often within one to three years.148  Unlike with traditional load growth,149 \nlarge load customers often have development timelines requiring interconnection to the \ntransmission system faster than traditional Network Upgrades can be built, necessitating a \nsufficient evaluation of alternative transmission technologies that can more quickly \naccommodate transmission service requests from Eligible Customers on behalf of large \nloads.150  The Commission has previously recognized that alternative transmission \ntechnologies have the potential to mitigate or defer the need for traditional Network \nUpgrades and often can be deployed both more quickly and at lower cost than traditional \nNetwork Upgrades, and therefore failing to consider whether alternative transmission \ntechnologies can meet transmission needs more efficiently or cost-effectively than \ntraditional Network Upgrades has the potential to render Commission-jurisdictional rates \n \n148 WATT and Advancing Modern Powerlines November 21 ANOPR Comments \nat 5-6. \n149 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at P 7 (explaining that the \nHILL proposal was needed in part due to large load customers frequently requesting \ntransmission service within months rather than years of their intended commercial \noperation, straining legacy regulatory frameworks and planning processes originally \ndesigned for slow, incremental, and predictable load growth); see also Commission Staff, \n2025 State of the Market Report 8 (Mar. 2026) (“[D]ata centers have characteristics \nunlike more traditional loads [including] size, strong desire for faster interconnection, and \npotential flexibility.”). \n150 Exec. Off. of the President, Winning the Race: America’s AI Action Plan 1-2, \n15 (July 2025), https://www.whitehouse.gov/wp-content/uploads/2025/07/Americas-AI-\nAction-Plan.pdf (explaining that accelerated deployment of AI data centers is a critical \nmatter of national security and international economic competitiveness, and \nrecommending federal policy action to optimize the existing grid through advanced grid \ntechnologies); WATT and Advancing Modern Powerlines November 21 ANOPR \nComments at 5-8 (“[Alternative transmission technologies’] deployment timelines are \nmore aligned with the interconnection needs of new large loads, which may only take 1-2 \nyears to construct.”); Industrial Customers November 21 ANOPR Comments at 28 \n(“Achieving speed-to-power in the near-term, while also protecting customers, will \nrequire the use of GETs, advanced reconductoring, and unlocking all available system \ncapacity.”); Energy Systems Integration Group, Historical and Modern Large Loads: \nCharacteristics, Context, and Industry Action to Meet Grid and Customer Needs 4           \n(Mar. 2026), https://www.esig.energy/wp-content/uploads/2026/03/ESIG-Historical-vs-\nModern-Large-Loads-white-paper-2026.pdf (describing the timing mismatch between \nhow long it takes to build a new data center and how long it takes to plan, permit, and \nbuild transmission)."},{"page":43,"startToken":16484,"endToken":16949,"text":"Docket No. EL26-67-000 \n- 43 - \nunjust and unreasonable.151  Further, to the extent Network Upgrade costs to \naccommodate an Eligible Customer’s request for transmission service on behalf of a large \nload are rolled into a transmission owner’s transmission revenue requirement, \ntransmission customers other than the Eligible Customer may bear a portion of those \nNetwork Upgrade costs, highlighting the need for clear and consistent provisions \nrequiring the evaluation of least-cost options like alternative transmission technologies to \nmitigate the rate impact on all transmission customers.    \n \nPJM should explain whether the Tariff remains just and reasonable without \nprovisions that:  (1) require the evaluation of alternative transmission technologies in \ntransmission service request studies, using models that are capable of evaluating the \ntransmission system to accurately account for advanced transmission technologies, in all \ninstances, without the need for a request from the Eligible Customer seeking transmission \nservice on behalf of a large load; and (2) if traditional Network Upgrades are selected \ninstead of alternative transmission technologies, inclusion in the study report to the \nEligible Customer seeking transmission service on behalf of a large load of a sufficiently \nclear demonstration of why alternative transmission technologies are not feasible (i.e., \nwould not resolve reliability violations identified or meet the relevant planning criteria) \nor would not result in lower costs or a faster timeline for accommodating the transmission \nservice request; or propose Tariff revisions establishing such provisions.  This \ntransparency and informational requirement is warranted for the regulatory scheme we \nare establishing for transmission service requests by Eligible Customers on behalf of \nlarge loads given demand from and the expedited development timelines for large load \ncustomers.  We underscore that we are not mandating the use of alternative transmission \ntechnologies.  To the extent stakeholders believe that specific characteristics of providing \ntransmission service to Eligible Customers on behalf of large loads warrant requirements \nbeyond those contemplated here, we seek further briefing. \n \nFinally, based on the record, it appears reasonable that such study processes, \nculminating in a report to the Eligible Customer with the results of the studies, including \nany Direct Assignment Facilities and Network Upgrades necessary to accommodate the \ntransmission service request as well as a non-binding good-faith estimate of the cost and \nthe time to construct such facilities, should take no more than 60-90 days calendar days to \n \n151 Improvements to Generator Interconnection Procs. & Agreements, Order              \nNo. 2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), \norder on reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC                    \n¶ 61,134 (2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & \nCost Allocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order \nNo. 1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC       \n¶ 61,026 (2025)."},{"page":44,"startToken":16949,"endToken":17427,"text":"Docket No. EL26-67-000 \n- 44 - \ncomplete.152  To the extent PJM or the Transmission Owners already have such \nprocedures and conduct such studies, but those processes are not included in the Tariff, \nPJM and the Transmission Owners should explain their existing processes and consider \nwhether amendments are necessary to the Tariff to memorialize those processes and also \naddress the concerns expressed herein.  Otherwise, PJM should explain whether the \nTariff remains just and reasonable without:  (1) sufficiently clear and consistent \nprovisions to evaluate the impact of providing the requested transmission service to \nEligible Customers on behalf of large loads, including identifying the Direct Assignment \nFacilities and Network Upgrades necessary to provide such service reliably;                          \n(2) provisions to appropriately recognize within the transmission service study process \nthe unique operational characteristics of large loads; (3) a study deadline of no more than \n60-90 calendar days; or propose Tariff revisions establishing them. \n \nThird, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks provisions addressing ongoing operational requirements for \ntransmission customers taking transmission service on behalf of large loads.  We are \nconcerned that without such requirements the rates, terms, and conditions of transmission \nservice may be unjust and unreasonable.  The unique nature of these large loads creates \nchallenges for operation of the transmission system and necessitates greater visibility and \noperational control when providing transmission service to transmission customers on \nbehalf of large loads, without which the reliability of the transmission system could be at \nrisk.153  For example, we are concerned that PJM’s Tariff does not require transmission \ncustomers to provide PJM hourly forecasts, telemetry data, and other data to ensure \nsufficient visibility or specify requirements for maintaining communication channels \nbetween PJM and the transmission customer on behalf of the large load.  Additionally, \nwe are concerned that the Tariff does not require transmission owners to install, and \ntransmission customers to pay for, equipment to enable PJM to monitor large loads for \nimpacts of, for example, fast-ramping load that may impact the transmission system too \nquickly to be captured by conventional data acquisition systems (e.g., the need for phasor \n \n152 Several commenters support a 60-day timeline.  See, e.g., Constellation \nNovember 21 ANOPR Comments at 26; Critical Loop December 5 ANOPR Comments \nat 8; EDF Power November 21 ANOPR Comments at 16; Tract November 21 ANOPR \nComments at 9.  Other commenters note that SPP’s HILL process has a 90-day timeline, \nor otherwise support a 90-day timeline.  See, e.g., AEMA November 21 ANOPR \nComments at 3; Eolian December 5 ANOPR Comments at 27; Industrial Customers \nNovember 21 ANOPR Comments at 20; PJM November 21 ANOPR Comments at 7; \nSPP November 21 ANOPR Comments at 16-17.  \n153 E.g., ATC November 21 ANOPR Comments at 14; CAISO November 21 \nANOPR Comments at 10 (citing NERC Characteristics and Risks of Large Loads); Herb \nSchrayshuen November 21 ANOPR Comments at 2-5."},{"page":45,"startToken":17427,"endToken":17877,"text":"Docket No. EL26-67-000 \n- 45 - \nmeasurement units or similar equipment).  We are also concerned that the Tariff does not \nrequire the transmission customer to enable PJM to remotely disconnect large loads when \nnecessary to maintain reliability of the transmission system, with the costs of such \nequipment directly assigned to the transmission customer, as well as the terms and \nconditions under which PJM may remotely disconnect the large load (e.g., emergency \nconditions, so that transmission equipment is not harmed).  Further, we are concerned \nthat the Tariff does not specify ramp rate or ride-through requirements with which the \ntransmission customer taking transmission service on behalf of the large load must \ncomply.  Lastly, we are concerned that the Tariff does not specify requirements for \nnecessary control technologies and/or protection systems that may be necessary to limit a \ntransmission customer’s withdrawals from the transmission system as appropriate.154  \nPJM should explain whether the Tariff remains just and reasonable without these or other \nongoing operational requirements as part of the rates, terms, and conditions of \ntransmission service or propose Tariff revisions establishing necessary ongoing \noperational requirements. \n \nFourth, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks pro forma provisions in a transmission service agreement \nbetween PJM and the transmission customer taking transmission service on behalf of a \nlarge load to memorialize the above terms (e.g., equipment requirements, data \nrequirements, remote disconnect capability).  We are concerned that, without such                 \npro forma provisions in a transmission service agreement between PJM and the \ntransmission customer, PJM may be unable to enforce ongoing operational requirements \nfor transmission customers taking transmission service on behalf of large loads.  PJM \nshould explain whether the Tariff remains just and reasonable without such pro forma \nprovisions in a transmission service agreement, or propose revisions to include pro forma \nprovisions memorializing the ongoing operational requirements in a transmission service \nagreement between PJM and the transmission customer. \nB. \nCost Shifting Risk Among Transmission Customers \n \nWe next preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks adequate mechanisms to mitigate the risk of cost shifting \namong transmission customers, which may result in unjust and unreasonable rates for \ntransmission service.  In particular, we are concerned about the apparent lack of:           \n(1) transparency regarding the assignment of Network Upgrades, and their associated \ncosts, that are needed to provide transmission service to Eligible Customers on behalf of \nlarge loads; and (2) a pro forma cost recovery agreement between PJM, the relevant \n \n154 Specifically, as discussed below, the Commission has found that such \nnecessary control technologies and/or protection schemes may be appropriate where \nEligible Customers are taking one of the new transmission services.  See infra P 87."},{"page":46,"startToken":17877,"endToken":18328,"text":"Docket No. EL26-67-000 \n- 46 - \ntransmission owner, and the Eligible Customer taking transmission service on behalf of \nlarge loads that help ensure that Eligible Customers bear the risk and are ultimately \nresponsible for costs incurred to provide transmission service, including the cost of \nNetwork Upgrades.  \n \nWe direct PJM and the Transmission Owners, to the extent the matters addressed \nherein implicate aspects of the Tariff over which they have the filing rights, to explain \nwhether the Tariff remains just and reasonable without (1) robust, accurate, and \nsystematic provision of data on PJM’s website in a single location, and in an easily \naccessible format that is searchable and allows users to filter the data, regarding the cost \nfor Network Upgrades needed to provide transmission service to Eligible Customers on \nbehalf of large loads; and (2) a pro forma cost recovery agreement between PJM, the \nrelevant transmission owner, and the Eligible Customer taking transmission service on \nbehalf of a large load, or to propose Tariff revisions to provide additional transparency \nand establish such a pro forma cost recovery agreement.  We encourage state regulators \nresponsible for setting retail rates to provide input to PJM regarding their transparency \nneeds. \n1. \nJurisdiction \n \nThe Commission has a duty to address the risk of cost shifting among transmission \ncustomers that may result in unjust and unreasonable transmission rates.  As explained \nabove, the Commission is obligated to ensure that the rates charged for jurisdictional \ntransmission service—as well as any practice directly affecting such rates—are just and \nreasonable and not unduly discriminatory or preferential.  With respect to the addition of \nlarge loads to the transmission system, the Commission has exclusive authority to ensure \nthat transmission rates are just and reasonable.  The costs of those upgrades to the \ntransmission system (i.e., Network Upgrades) necessary to provide transmission service \nto Eligible Customers on behalf of large loads are inputs to jurisdictional transmission \nrates, and thus directly affect the Commission-jurisdictional rates paid by transmission \ncustomers.  To fulfill its responsibility to ensure that transmission rates are just and \nreasonable, the Commission must act to address the risk of cost shifting among \ntransmission customers due to (1) the process transmission providers and/or transmission \nowners use to evaluate the facilities needed, and the associated costs, for the provision of \ntransmission service to Eligible Customers on behalf of large loads and (2) speculative \ntransmission service requests by Eligible Customers on behalf of large loads that could \nresult in unjust and unreasonable transmission rates. \n \nIn response to the ANOPR, many commenters raise concerns about the impact that \nlarge load additions can have on retail ratepayers, particularly the concern that other retail \nratepayers may be forced to subsidize Network Upgrades needed to add large loads to the"},{"page":47,"startToken":18328,"endToken":18740,"text":"Docket No. EL26-67-000 \n- 47 - \ntransmission system.155  While we appreciate and are similarly concerned about this \nissue, the Commission is limited to addressing jurisdictional transmission rates and as \nsuch, we do so herein.  As the Commission has explained, states determine how \nCommission-approved rates are collected among the relevant retail consumers along with \nthe rates for state-jurisdictional matters.156  Specifically, states have authority over how \nthe wholesale costs of providing electricity, including transmission of such electricity, to \nthose retail customers are recovered through retail rates.157  We are encouraged by efforts \ntaken by states to reform retail tariffs to address the potential for retail cost shifting as \nlarge loads come online,158 as well as voluntary efforts by transmission owners to protect \nretail ratepayers through cost recovery agreements with large loads.159  We are also \nencouraged by the execution of the President’s Ratepayer Protection Pledge, through \nwhich data center developers have committed to shield retail ratepayers from increased \nelectricity prices.160 \n \nWe expect that the additional cost transparency measures proposed in the \nfollowing section will give state public utility commissions and other state regulators the \ninformation necessary to allow them to understand which transmission costs are caused \nby which transmission customers, so that they can sub-allocate these costs to the \nappropriate retail customers.  Indeed, the Commission’s objective in this proceeding is to \nrespect the cooperative federalism approach established under the FPA.  Specifically, one \nof the benefits of providing transparency on the costs of Network Upgrades necessary to \nprovide transmission service to Eligible Customers on behalf of large loads is so that state \nregulators can use that information to protect residential and small commercial customers \n \n155 See, e.g., Illinois AG November 21 ANOPR Comments at 11-12; Missouri \nCommission November 21 ANOPR Comments at 11; OMS November 21 ANOPR \nComments at 4. \n156 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. \n157 Id. P 68. \n158 See, e.g., Pennsylvania Commission November 21 ANOPR Comments at 7-8; \nMaryland Commission November 21 ANOPR Comments at 2; Virginia Commission \nNovember 21 ANOPR Comments at 4-5 \n159 See, e.g., Commonwealth Edison Co. 194 FERC ¶ 61,106; Commonwealth \nEdison Co., 194 FERC ¶ 61,109; Commonwealth Edison Co., 194 FERC ¶ 61,110; \nCommonwealth Edison Co., 194 FERC ¶ 61,113 (2026); PECO Energy Co., 193 FERC    \n¶ 61,148; Dayton Power & Light Co., 192 FERC ¶ 61,103; Dayton Power & Light Co., \n189 FERC ¶ 61,220 (2024). \n160 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":48,"startToken":18740,"endToken":19137,"text":"Docket No. EL26-67-000 \n- 48 - \nby incorporating those costs into the retail rates as they see fit given their authority to set \nrates for different classes of retail customers.  We encourage state public utility \ncommissions, state regulators, and state consumer advocates to submit comments \nexplaining whether this information is sufficient and granular enough or to submit \ncomments explaining precisely which additional information on transmission cost \nallocation may be needed to inform proper state-jurisdictional cost allocation.  \n2. \nAdditional Cost Transparency \n \nWe preliminarily find that PJM’s Tariff appears to be unjust and unreasonable or \nunduly discriminatory or preferential because it does not contain provisions requiring the \nprovision of data on PJM’s website in a single location, and in an easily accessible format \nthat is searchable and allows users to filter the data, on transmission service requested by \nEligible Customers on behalf of large loads, for Network Upgrades evaluated in the local \ntransmission planning process that are needed to provide transmission service to Eligible \nCustomers on behalf of those large loads, and the costs for those Network Upgrades.  We \npreliminarily find that cost transparency measures are needed to provide stakeholders \nwith sufficient information and visibility regarding the Network Upgrades, and their \nassociated costs, needed to provide transmission service to Eligible Customers on behalf \nof large loads.   \n \nAs discussed above, Network Upgrades needed to accommodate a new \ntransmission service request or designation of new network load may be designated as \nlocal transmission facilities (i.e., Supplemental Projects) or contribute to regional \ntransmission system needs and be addressed by a Required Transmission Enhancement in \nthe RTEP.  PJM’s Tariff Schedule 12 Appendix and Appendix A include the cost \nresponsibility assignments for regional transmission projects selected through the RTEP \nprocess.  In addition, Attachment M-3 of PJM’s Tariff provides procedures for \nstakeholder review and comment on Supplemental Projects identified through \ntransmission owners’ local transmission planning process in the Transmission Expansion \nAdvisory Committee (230 kV or above) and Subregional RTEP Committee (below                 \n230 kV) and as part of a transmission owner’s Local Plan, before the Local Plan is \nsubmitted for integration into the RTEP.161  PJM’s website also includes a list of \nRequired Transmission Enhancements and Supplemental Projects with their project \nstatus, cost, and cost allocation.162   \n \n161 See PJM Tariff, attach. M-3, § (c) (Procedures for Review of Attachment M-3 \nProjects) (1.0.0). \n162 PJM, Project Status & Cost Allocation, \nhttps://www.pjm.com/planning/m/project-construction."},{"page":49,"startToken":19137,"endToken":19624,"text":"Docket No. EL26-67-000 \n- 49 - \n \nHowever, PJM’s Tariff does not appear to require that information identifying the \nNetwork Upgrades needed to provide transmission service to Eligible Customers on \nbehalf of large loads and the costs of those Network Upgrades determined through local \ntransmission planning processes be readily available on PJM’s website in a single \nlocation, and in an easily accessible format that is searchable and allows users to filter the \ndata.  We acknowledge that PJM’s website provides information concerning certain \ntransmission projects, including Supplemental Projects, such as project status, cost, cost \nallocation, and the type of equipment and upgrade, and includes the primary driver for \neach transmission project (i.e., load growth), but these postings do not appear to be \nspecific to transmission projects needed to provide transmission service to Eligible \nCustomers on behalf of large loads.  The speed and scale with which Eligible Customers \nare seeking transmission service on behalf of large loads makes it difficult for interested \nparties, including transmission customers and state regulators, to accurately assess which \ntransmission costs are driven by requests for transmission service by Eligible Customers \nto serve large loads.  Further, as PJM acknowledges, it forecasts significant peak load \ngrowth, but there is a large cone of uncertainty around the trajectory and amplitude of \nfuture demand growth.163  We are concerned that the potentially speculative nature of \nrequests for transmission service by Eligible Customers on behalf of large loads,164 the \nspeed and scale with which large loads are seeking to be added to the transmission \nsystem, the projected need for significant Network Upgrades to provide transmission \nservice to Eligible Customers on behalf of large loads, and the lack of centralized \ninformation on the associated transmission costs in PJM hamper the ability of the \nCommission and stakeholders (including transmission customers and state regulators165) \nto understand and accurately assess the relationship between the addition of large loads to \nthe transmission system and wholesale transmission costs.   \n \n163 See PJM Board Letter at 1. \n164 See supra P 56. \n165 See Transcript, NARUC Collaborative, Docket No. AD24-7-000, at 16-17 \n(Feb. 11, 2026) (Chair Bagot, Virginia) (asserting that additional transparency at the RTO \nlevel would help the states get the information they need to “identify . . . that bucket of \ncosts” related to large load-driven transmission costs), 19 (Commissioner Chattopadhyay, \nNew Hampshire) (noting the need for “all parties to be able to see things transparently” \nwith respect to wholesale transmission costs), 35-37 (Chair Martz, Iowa) (raising concern \nthat currently RTOs/ISOs do not have to clearly explain when a “bucket of costs is \nspecifically for this large load” and noting that “if we, at the state level, can’t see the \ndriver [of transmission costs], we can’t assign the cost to the causer[,] [a]nd so we need \nthat clarity”), 69-70 (Chair Myers, Arizona) (“[B]eing able to allocate the large load costs \nto the correct bucket when it gets to the states is kind of a top priority.”)."},{"page":50,"startToken":19624,"endToken":20098,"text":"Docket No. EL26-67-000 \n- 50 - \n \nWe are concerned that without sufficient transparency regarding the Network \nUpgrades, and their associated costs, needed to provide transmission service to Eligible \nCustomers on behalf of large loads, stakeholders may lack information and visibility \nregarding the costs driven by large load additions.  We preliminarily find that, for \nNetwork Upgrades evaluated in the local transmission planning process166 that are \nneeded to provide transmission service to Eligible Customers on behalf of large loads, \nPJM must provide clear, timely, and detailed information regarding the extent to which \nrequests for transmission service by Eligible Customers on behalf of large loads \nnecessitate Network Upgrades to accommodate the transmission service to Eligible \nCustomers on behalf of large loads, as well as the costs of those Network Upgrades. \n \nWe note that centralized information regarding Network Upgrades needed to \naccommodate requests for transmission service by Eligible Customers on behalf of large \nloads would also help inform stakeholders at the state and local level to address \naffordability and other challenges posed by the integration of large loads.  Indeed, \ncommenters state that the opaque nature of requests for transmission service by Eligible \nCustomers on behalf of large loads, and the associated Network Upgrades required to \nprovide that transmission service, prevent wholesale and retail customers, states, and \nother stakeholders from understanding such costs.167        \n \n166 Our concern with transparency regarding Network Upgrades needed to provide \ntransmission service to Eligible Customers on behalf of large loads, as well as the costs of \nsuch upgrades, is limited to Network Upgrades planned through the local transmission \nplanning process.  While we acknowledge that in Order No. 890, the Commission \nadopted requirements for RTOs/ISOs, as well as for transmission owners to the extent \nthat they perform transmission planning within an RTO/ISO, to have open and \ntransparent transmission planning processes, there are additional requirements that apply \nto regional transmission planning processes (that do not apply to local transmission \nfacilities) and thus is relevant to the distinction here.  Specifically, under Order No. 1000, \npublic utility transmission providers, including RTOs/ISOs, must evaluate as part of their \nregional transmission planning process whether there are transmission facilities that more \nefficiently or cost-effectively meet the transmission planning region’s identified \ntransmission needs.  See Order No. 1000, 136 FERC ¶ 61,051 at P 11. \n167 See OCC November 21 ANOPR Comments at 3 (“Consumers, state advocates \nand state regulatory commissions have a right to know which entities are seeking            \nlarge-load interconnections, the nature of the requested service, and how related costs \ncould flow through to transmission and distribution rates.”); U.S. House of \nRepresentatives Committee on Energy and Commerce Ranking Members November 21 \nANOPR Comments at 2 (urging the Commission to “require sufficient transparency from \ngrid operators so it can determine which specific large load facilities are responsible for \ngrid upgrade needs”); see also CPUC November 21 ANOPR Comments at 16-17"},{"page":51,"startToken":20098,"endToken":20558,"text":"Docket No. EL26-67-000 \n- 51 - \n \nAccordingly, we preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it does not require the provision of data on PJM’s website in a \nsingle location, and in an easily accessible format that is searchable and allows users to \nfilter the data, that identifies the Network Upgrades that are needed to accommodate \nrequests for transmission service by Eligible Customers on behalf of large loads, and the \ncosts of those Network Upgrades.  PJM should explain whether the Tariff remains just \nand reasonable without provisions that would require PJM and the Transmission Owners \nto publicly post and regularly update data that details:  (1) the aggregate amounts of \nproposed large load additions in PJM’s footprint, including the aggregate amounts in \neach transmission pricing zone; (2) the planned Network Upgrades needed to provide \ntransmission service to Eligible Customers on behalf of large loads, identified by type of \nequipment and Network Upgrade (e.g., new substation, reconductoring, a new                    \nhigh-voltage transmission line) for each transmission service request; and (3) cost \nestimates for those Network Upgrades; or propose such Tariff revisions.  PJM and the \nTransmission Owners should also consider what other data related to transmission costs \nresulting from the provision of transmission service to Eligible Customers on behalf of \nlarge loads would be useful to include on PJM’s website.  To the extent there are \nconcerns about data confidentiality, PJM and the Transmission Owners should consider \nwhether there are ways to mitigate those concerns while still providing the necessary \ntransparency. \n3. \nCost Recovery Agreements \n \nWe next preliminarily find that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks adequate mechanisms to mitigate the risk of cost shifting \namong transmission customers, which may result in unjust and unreasonable rates for \ntransmission service.  In particular, we are concerned about the apparent lack of a              \npro forma cost recovery agreement between PJM, the relevant transmission owner, and \nthe Eligible Customer taking transmission service on behalf of large loads that help \nensure that Eligible Customers bear the risk and are ultimately responsible for costs \nincurred to provide transmission service, including the cost of Network Upgrades.  \n \nSeveral commenters discuss the risk of cost shifting among transmission \ncustomers that could result from transmission service requests by Eligible Customers on \nbehalf of large loads.168  Commenters also argue that retail-level large load tariffs do not \n \n(asserting that the public posting of large load cost responsibility determinations would \nimprove transparency, to the benefit of businesses and ratepayers).  \n168 See, e.g., Buckeye November 21 ANOPR Comments at 8-13; APPA    \nNovember 21 ANOPR Comments at 6 (“Wholesale transmission customers in particular \ncould be left shouldering massive costs if new large loads do not ultimately attain or \nmaintain the level of electricity demand that is being forecasted.”); NRECA"},{"page":52,"startToken":20558,"endToken":20983,"text":"Docket No. EL26-67-000 \n- 52 - \nprotect wholesale transmission customers from cost shifting.169  Specifically, commenters \nin the record contend that, while a retail-level large load tariff protects the load serving \nentity taking wholesale transmission service and its retail customers, it fails “to provide \nany mechanism to protect other wholesale transmission customers” from stranded \ntransmission costs.170  The Kansas Commission states that while its Large Load Power \nServices rate plan that requires large loads to make minimum payments toward \ntransmission costs protects retail ratepayers from large-load driven transmission costs, it \ncannot protect against cost shifting associated with regional transmission buildout where \n“the large loads that formed the basis for the [regional] transmission plans do not \nmaterialize, leaving only existing customers to pay for generational expansions of the \ntransmission grid.”171  TAPS contends, moreover, that it is not sufficient for the \nCommission to rely on transmission owners to voluntarily file cost recovery agreements \nto protect transmission customers from cost shifting for Network Upgrades.172   \n \nWe are likewise concerned that there may be speculative transmission service \nrequests by Eligible Customers on behalf of large loads that could result in cost shifting \namong transmission customers, which may lead to unjust and unreasonable increases in \njurisdictional transmission rates.  When a transmission owner constructs Network \nUpgrades to accommodate an Eligible Customer’s request for transmission service on \nbehalf of a large load, those transmission costs will be included in the transmission \nowner’s transmission revenue requirement.  If, however, the Eligible Customer takes less \ntransmission service than anticipated because the large load operates at a lower demand \n \nNovember 21 ANOPR Comments at 21 (noting the risk that other transmission customers \ncould bear stranded upgrade costs caused by large loads that they cannot absorb); TAPS \nNovember 21 ANOPR Comments at 22-24; California DWR November 21 ANOPR \nComments at 8. \n169 TAPS November 21 ANOPR Comments at 26 (“[A] number of state \ncommissions are moving forward with retail large load tariffs, which provide for varying \nprotections, but may not require the revenues and minimum demand levels to be included \nin wholesale transmission rates.”); Buckeye November 21 ANOPR Comments at 14-16; \nKansas Commission November 21 ANOPR Comments at 15-16. \n170 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 \nANOPR Comments at 26-27 & nn.50-51.  \n171 Kansas Commission November 21 ANOPR Comments at 11-12.  \n172 TAPS November 21 ANOPR Comments at 25-26 (noting that AES Ohio \n“committed to reflecting the payments it received from the data center in its   \nCommission-jurisdictional transmission revenue requirement so that other customers are \nprotected,” in a Construction Service Agreement with Amazon)."},{"page":53,"startToken":20983,"endToken":21451,"text":"Docket No. EL26-67-000 \n- 53 - \nthan anticipated or fails to materialize at all, other transmission customers may see an \nincrease in transmission rates.  In such a situation, those other transmission customers \nmay have to pay for potentially unnecessary Network Upgrades that they neither caused \nthe need for nor benefit commensurately from.  In other words, this introduces the risk \nthat costs may be unfairly shifted to other transmission customers, which may result in \nthose costs then being passed through to residential customers, among others. \n \nPJM’s Tariff does not require cost recovery agreements between PJM, the relevant \ntransmission owner, and the Eligible Customer taking transmission service on behalf of a \nlarge load.  Such agreements would help ensure that the Eligible Customer makes a \nminimum contribution to the transmission owner’s transmission revenue requirement \ncommensurate with the costs incurred to provide the requested transmission service, \nincluding the costs of any needed Network Upgrades.  Absent such cost recovery \nagreements, we are concerned that there is no mechanism to help ensure that Eligible \nCustomers taking transmission service on behalf of large loads (as opposed to other \ntransmission customers) bear the risk of, and are ultimately responsible for, the costs \nincurred to provide them with the requested transmission service, including the costs of \nany needed Network Upgrades.   \n \nAccordingly, we preliminarily find that, in order to prevent unjust and \nunreasonable cost shifting among transmission customers, it appears necessary for PJM, \nthe relevant transmission owner, and the Eligible Customer taking transmission service \non behalf of a large load to enter into a cost recovery agreement that requires the Eligible \nCustomer to make a minimum contribution toward the transmission owner’s transmission \nrevenue requirement, if the Eligible Customer ultimately takes less transmission service \nthan anticipated because the large load does not materialize as planned or is not \ndeveloped at all.  We preliminarily find that such cost recovery agreements are necessary \nto help ensure that the Eligible Customer is responsible for timely paying the costs of \nlarge load-driven transmission (i.e., the costs incurred to provide them with the requested \ntransmission service, including the costs of any needed Network Upgrades), rather than \nhaving those costs paid by other transmission customers that neither caused the need for \nnor benefit commensurately from those Network Upgrades.173  Our preliminary finding is \nnot intended to alter or call into question existing regional cost allocation methods for \nNetwork Upgrades, but instead is focused on helping to prevent cost shifting among \ntransmission customers.   \n \nWe note that several transmission owners and large load customers have filed cost \nrecovery agreements (Transmission Security Agreements or Construction Service \nAgreements) with the Commission that guarantee minimum contributions from a large \n \n173 See, e.g., Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 \n(D.C. Cir. 2004); Ill. Com. Comm’n v. FERC, 576 F.3d 470, 476 (7th Cir. 2009)."},{"page":54,"startToken":21451,"endToken":21925,"text":"Docket No. EL26-67-000 \n- 54 - \nload customer (rather than from the Eligible Customer taking transmission service on \nbehalf of the large load customer) to the transmission owner’s transmission revenue \nrequirement.174  Although we decline to preliminarily find that cost recovery agreements \nbetween the transmission owner and the large load customer (rather than the Eligible \nCustomer) are necessary to ensure just and reasonable transmission rates, we continue to \nfind that such agreements directly affect Commission-jurisdictional transmission rates.  \nTherefore, to the extent a transmission owner and a large load customer enter into a cost \nrecovery agreement (whether voluntarily or pursuant to state law) through which the \nlarge load customer guarantees contributions to the transmission owner’s               \nCommission-jurisdictional transmission revenue requirement, we find that such an \nagreement should be filed with the Commission.175  To reduce duplicative credit \nrequirements and transaction costs, we direct further briefing on whether it would be \nappropriate for such an agreement to substitute for the requirement on the Eligible \nCustomer to enter into a cost recovery agreement with the transmission owner, if the \nagreement with the large load customer provided comparable or greater protection \nagainst cost shifting among transmission customers than an agreement between the \ntransmission owner and the Eligible Customer would.   \n \nIn addition to our preliminary finding that PJM’s Tariff is unjust and unreasonable \nbecause it lacks a pro forma cost recovery agreement of this type, we also preliminarily \nfind that the minimum contribution required pursuant to such an agreement should be \nbased on the level of jurisdictional transmission service (in MW) requested by the \nEligible Customer on behalf of the large load.  That figure is in turn tied to how PJM \nand/or Transmission Owners will study the requested transmission service and determine \nany necessary Network Upgrades that must be developed to provide the requested \ntransmission service.  We note, however, that there may be other just and reasonable \nmethods for determining this minimum contribution, including methods that account for \npotential timing differences between when costs are incurred to develop needed Network \nUpgrades and the pace at which the large load ramps toward energizing at its full level of \nrequested service.  We further preliminarily find that the cost recovery agreement should \ninclude a credit support (or other financial security) requirement sufficient to secure the \nobligations of the Eligible Customer taking transmission service on behalf of a large load \nto pay the amounts owed pursuant to the cost recovery agreement.  We find that a cost \nrecovery agreement with a specified minimum financial contribution and financial \nsecurity sufficient to secure such contribution is necessary to mitigate cost shifting if the \n \n174 See supra note 159. \n175 We emphasize that this finding is in no way intended to preempt or interfere \nwith the ability of states to implement ratepayer protection measures designed to mitigate \ncost shifting among retail customers, such as through state-jurisdictional large load \ntariffs."},{"page":55,"startToken":21925,"endToken":22360,"text":"Docket No. EL26-67-000 \n- 55 - \nEligible Customer ultimately takes less transmission service than anticipated because the \nlarge load does not materialize as planned or is not developed at all.  We preliminarily \nfind that an Eligible Customer may include a credit support or other financial security \nposted by a large load as part of a retail agreement to avoid creating duplicative credit \nsupport requirements.  PJM should explain why such a pro forma cost recovery \nagreement is not necessary to ensure just and reasonable rates, or propose such a                   \npro forma cost recovery agreement.  To the extent that stakeholders believe that other \nmechanisms could address our cost shifting concerns, we seek further briefing as \ndiscussed below.176 \n \nLastly, we expect that any payments made by an Eligible Customer to a \ntransmission owner pursuant to such a cost recovery agreement (or by a large load to a \ntransmission owner pursuant to other voluntary agreement) will be appropriately credited \ntoward transmission owners’ transmission revenue requirements consistent with the \nCommission’s cost-of-service regulations.177  We preliminarily find that it appears \nreasonable for filers of formula rates to provide a separate workpaper in the annual \ninformational filing describing how any payments made pursuant to a cost recovery \nagreement are reflected in the transmission owner’s transmission formula rate. \nC. \nExtending New Transmission Services to Eligible Customers Taking \nService on Behalf of Flexible Large Loads \n \nIn response to the ANOPR, a number of commenters argue that certain large loads \nare able to limit their withdrawals from the transmission system under certain conditions.  \nNamely, commenters observe that flexible large loads178 can quickly and verifiably adjust \ntheir consumption in response to system conditions or price signals.179  Commenters in \nthe ANOPR also observe that, where load studies and system planning consider the \nflexible nature of large loads, flexible large loads can potentially defer or reduce the need \n \n176 See infra P 107.  \n177 See 18 C.F.R. pt. 101 (2025). \n178 For purposes of this order, “flexible” large loads are a subset of large loads, as \nused in this order, that are not co-located with generation, but are willing and able to limit \ntheir energy withdrawals from the transmission system under certain conditions. \n179 See, e.g., AEMA November 21 ANOPR Comments at 1-2; Land Trust Alliance \nNovember 21 ANOPR Comments at 10; California DWR November 21 ANOPR \nComments at 5; CEBA November 21 ANOPR Comments at 14-15; ClearPath            \nNovember 21 ANOPR Comments at 2-4; Digital Energy Council November 21 ANOPR \nComments at 1; EDF Power November 21 ANOPR Comments at 4; Emerald             \nNovember 21 ANOPR Comments at 2; Verrus November 21 ANOPR Comments at 4."},{"page":56,"startToken":22360,"endToken":22801,"text":"Docket No. EL26-67-000 \n- 56 - \nfor Network Upgrades, among other potential benefits.180  In recognition of this \nflexibility, many commenters support new transmission services that reflect the \noperational capabilities of flexible large loads, including interim NITS while Network \nUpgrades are constructed, and non-firm transmission service.181   \n \nWe preliminarily find that PJM’s Tariff appears to be unjust and unreasonable \nbecause it does not include transmission services that reflect Eligible Customers taking \ntransmission service on behalf of flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions.  The transmission services \navailable to Eligible Customers, including on behalf of flexible large loads, in PJM are \nNITS and firm and non-firm Point-to-Point Transmission Service.182  While these remain \njust and reasonable options for an Eligible Customer to take on behalf of a flexible large \nload, based on the record before us, we preliminarily find that new transmission services \nshould be available to reflect the operational reality that large loads may use the \ntransmission system to differing extents and certain large loads are willing and able to \nlimit their use of the transmission system under certain conditions.183  The Commission \nfound that Eligible Customers taking transmission service on behalf of Eligible Load \nshould be allowed to choose a transmission service that aligns with their use of the \ntransmission system and therefore aligns the charges for service with the benefits \nreceived.184  As the record suggests, Eligible Customers taking transmission service on \nbehalf of flexible large load also may be willing and able to limit their use of the \ntransmission system under certain conditions.  As recognized in the ANOPR record, load \n \n180 See, e.g., AEMA November 21 ANOPR Comments at 5; ELCON               \nNovember 21 ANOPR Comments at 9; Emerald November 21 ANOPR Comments             \nat 6-7; Institute for Progress November 21 ANOPR Comments at 11; Land Trust Alliance \nNovember 21 ANOPR Comments at 10; LS Power November 21 ANOPR Comments        \nat 5; Microsoft November 21 ANOPR Comments at 10-11; National Grid November 21 \nANOPR Comments at 19-20; OMS November 21 ANOPR Comments at 13-14; \nSoutheast PIOs November 21 ANOPR Comments at 50. \n181 See, e.g., Constellation November 21 ANOPR Comments at 24-25; Calibrant \nNovember 21 ANOPR Comments at 2-4; Critical Loop November 21 ANOPR \nComments at 2; Digital Power Network November 21 ANOPR Comments at 3; PIOs \nNovember 21 ANOPR Comments at 27-28; Splight November 21 ANOPR Comments          \nat 3-4. \n182 See supra P 19 (describing existing transmission services in PJM). \n183 See supra P 85.  \n184 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at P 103."},{"page":57,"startToken":22801,"endToken":23253,"text":"Docket No. EL26-67-000 \n- 57 - \nflexibility can avoid inefficient and costly transmission system build-out.185  In addition, \ntransmission services that reflect that flexible large loads are willing and able to limit \ntheir withdrawals from the transmission system under certain conditions could help \ntimely interconnect flexible large loads.186  Entities in the PJM footprint acknowledge the \nimportance of facilitating load flexibility.187 \n \nTherefore, we are concerned that PJM’s Tariff does not include transmission \nservices that reflect the use of the transmission system by Eligible Customers on behalf of \nflexible large load, on both an interim and permanent basis.  PJM should explain whether \nthe Tariff remains just and reasonable without the transmission services described by the \nCommission in the PJM Co-Location Order being available to Eligible Customers taking \ntransmission service on behalf of flexible large loads, or propose appropriate Tariff \nrevisions.  Specifically, PJM should explain whether the Tariff remains just and \nreasonable without (1) an interim non-firm network transmission service while Network \nUpgrades are being constructed (i.e., interim NITS) and (2) permanent firm and non-firm \ncontract demand transmission services (transmission service up to a specified MW \nquantity, i.e., the contract level, on a firm or non-firm basis).188  Finally, we note that the \nCommission has found it just and reasonable that, in order for an Eligible Customer to \n \n185 See supra P 85; see also PJM Co-Location Order, 193 FERC ¶ 61,217                 \nat PP 160, 177, 199 (finding that new transmission service options reflect a co-located \nload’s ability to limit withdrawals from the transmission system and potentially avoid \ncostly and inefficient transmission system buildout that may not be necessary). \n186 See supra P 85; see also PJM Co-Location Order, 193 FERC ¶ 61,217                          \nat PP 201 (finding that the interim, non-firm transmission service will facilitate the \n“timely” provision of transmission service and that “[t]his willingness to curtail would \npotentially allow them to obtain service more quickly”), 205 (recognizing that parties \nargue that co-located loads may be able to receive transmission service faster with use of \na new, limited transmission service product than they would if they selected NITS, to the \nextent that providing NITS would require Network Upgrades that the limited \ntransmission service would not). \n187 See, e.g., Constellation November 21 ANOPR Comments at 23-24; Load \nFlexibility Parties November 21 ANOPR Comments at 2-5; State Entities November 21 \nANOPR Comments at 4. \n188 In an order also issued today, the Commission established as just and \nreasonable certain rates, terms, and conditions for the new transmission services directed \nin the PJM Co-Location Order, which include portions of PJM’s and the Transmission \nOwners’ proposals submitted in the briefs, and directed further compliance filings.  See \ngenerally PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209."},{"page":58,"startToken":23253,"endToken":23629,"text":"Docket No. EL26-67-000 \n- 58 - \ntake interim NITS, firm contract demand transmission service, and non-firm contract \ndemand transmission service, 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 approved level.189 \nD. \nInterconnection Customers Serving Electrically Proximate Large Load \nand Co-Located Load \n \nIn response to the ANOPR, a number of commenters agree that the ability to study \nnew load and new generation together, when physically or electrically proximate, \npresents system benefits and can help address the challenges posed by large load \nadditions.190  Commenters argue that studies that consider large load and generation \ntogether present a more complete picture of the grid and can enable the identification of \nmore accurate, efficient, and cost-effective transmission solutions by minimizing system \nimpacts.191  As a result, this can speed up the interconnection process for both large loads \nand generation, and shorten energization timelines,192 which commenters contend \nreduces uncertainty for both parties193 and “is necessary to match the pace of AI \ninnovation in the United States.”194  CEBA also highlights that cost and timeline factors \ndrive developers to submit multiple requests for price and timing discovery, which \n \n189 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n190 See e.g., DCC November 21 ANOPR Comments at 5-6; DTE November 21 \nANOPR Comments at 11; Google November 21 ANOPR Comments at 7; International \nEnergy Credit Association November 21 ANOPR Comments at 10; Terraflux                \nNovember 21 ANOPR Comments at 1. \n191 AEU November 21 ANOPR Comments at 13; ClearPath November 21 \nANOPR Comments at 4; DCC November 21 ANOPR Comments at 5; DTE               \nNovember 21 ANOPR Comments at 8-11; ENGIE November 21 ANOPR Comments             \nat 6; Entergy November 21 ANOPR Comments at 5; Geronimo November 21 ANOPR \nComments at 17-18; Information Technology Industry Council November 21 ANOPR \nComments at 2. \n192 DCC November 21 ANOPR Comments at 5; DTE November 21 ANOPR \nComments at 8-11; Information Technology Industry Council November 21 ANOPR \nComments at 2; Microsoft November 21 ANOPR Comments at 8-9; Verrus December 5 \nANOPR Comments at 9. \n193 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 \nANOPR Comments at 8. \n194 Microsoft November 21 ANOPR Comments at 8-9."},{"page":59,"startToken":23629,"endToken":23980,"text":"Docket No. EL26-67-000 \n- 59 - \ninflates queue volumes, distorts demand and supply forecasts, and causes significant \ndelays when projects withdraw late after finding costs or energization timelines \nuneconomic.195  Other benefits to a joint study identified by commenters include \nimproving load forecasting and siting decisions196 and reducing the need for critical \nsupply chain components.197   \n \nCommenters contend that current generator interconnection study processes may \nnot adequately capture generation and load, including by failing to model known \nelectrically proximate large load in base case assumptions, which may result in inaccurate \nstudies and inefficient system build-out.198  For example, Eolian states that in its \nexperience developing a project in PJM, the failure of the generator interconnection study \nprocess to reflect reasonably expected load conditions on the grid models triggered overly \ncostly Network Upgrades and caused the cancellation of generation project that could \nhave reliably served adjacent load growth.199   \n \nCommenters in the ANOPR proceeding argue that the current state of the \ngenerator interconnection queue is not meeting the expeditious time frame needed to \nmatch the pace of large load additions and ensure the safe and reliable interconnection of \nthese loads.200  For example, Oracle states that one of the most significant and \nwidespread delays it encounters when siting data centers in the U.S. is access to sufficient \nenergy.201  Similarly, Helion contends that more than half of U.S. developers now \nidentify interconnection delays as the single biggest barrier to adding new generation \n \n195 CEBA November 21 ANOPR Comments at 8. \n196 ELCON November 21 ANOPR Comments at 5; Maryland Commission \nNovember 21 ANOPR Comments at 6-7.  \n197 AEU November 21 ANOPR Comments at 13. \n198 Base Power November 21 ANOPR Comments at 7; Eolian November 21 \nANOPR Comments at 18-19; Eolian May 19 ANOPR Comments at 2; Longroad \nNovember 21 ANOPR Comments at 8. \n199 Eolian May 19 ANOPR Comments at 10. \n200 See, e.g., AEP December 5 ANOPR Comments at 1; DCC November 21 \nANOPR Comments at 8; esVolta November 21 ANOPR Comments at 11-12; Oracle \nMay 1 ANOPR Comments at 4.  \n201 Oracle November 21 ANOPR Comments at 1."},{"page":60,"startToken":23980,"endToken":24334,"text":"Docket No. EL26-67-000 \n- 60 - \ncapacity.202  Commenters contend that if large load interconnection proceeds more \nquickly than new generation can come online, the result could be price increases for \nconsumers.203   \n \nA number of commenters support expedited interconnection studies for new \ngeneration paired with load.204  Some commenters argue that one solution to generator \ninterconnection delays may be the creation of time-limited or conditional interconnection \nservice for generators serving large loads, which could require less time for initial \ngenerator interconnection studies and improve speed to power.205  For example, several \ncommenters express support for SPP’s HILLGA proposal as a model and urge the \nCommission to establish nationwide rules similar to that approach.206  Other commenters \nsuggest reforms to expedite studies for new generation paired with large loads at existing \npoints of interconnection that have already been studied, arguing it is unjust and \nunreasonable not to fully utilize existing infrastructure and proven reliability paths while \nnew load waits for service.207   \n1. \nJurisdiction \n \nThe Commission’s statutory authority includes jurisdiction over the wholesale sale \nand transmission of electricity in interstate commerce, including the facilities used for \n \n202 Helion November 21 ANOPR Comments at 1 (citing Third Way, Picking Up \nthe PACE:  A Comprehensive Analysis of Available Pathways to Accelerating Clean \nEnergy (PACE) (Nov. 2025)). \n203 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR \nComments at 6-7, 11.  \n204 See, e.g., DTE November 21 ANOPR Comments at 8; ENGIE November 21 \nANOPR Comments at 4; International Energy Credit Association November 21 ANOPR \nComments at 8; Meta November 21 ANOPR Comments at 5-6; Ohio FEA November 21 \nANOPR Comments at 5.  \n205 AEP December 5 ANOPR Comments at 12; AEU November 21 ANOPR \nComments at 13; Google December 5 ANOPR Comments at 15; see also Duke \nNovember 21 ANOPR Comments at 21-22.  \n206 AEP December 5 ANOPR Comments at 4; Crusoe December 5 ANOPR \nComments at 7; Enchanted Rock November 21 ANOPR Comments at 4; Google \nNovember 21 ANOPR Comments at 7; GridStor November 21 ANOPR Comments at 5; \nVerrus November 21 ANOPR Comments at 9. \n207 Constellation June 5 ANOPR Comments at 8-9."},{"page":61,"startToken":24334,"endToken":24757,"text":"Docket No. EL26-67-000 \n- 61 - \nsuch sale and transmission.208  The Commission also has exclusive jurisdiction to \nregulate the procedures and agreements applicable to generating facilities seeking to \ninterconnect to a Commission-jurisdictional distribution facility or transmission \nfacility.209  In the PJM Co-Location Order, the Commission observed that a generator’s \ninterconnection to the interstate transmission system “does not fall outside of the \nCommission’s jurisdiction merely because there is [c]o-[l]ocated [l]oad behind the \ngenerator’s point of interconnection.”210  By the same token, the Commission retains \njurisdiction over a generator’s interconnection even where the generator plans to serve an \nelectrically proximate large load.   \n \nWe recognize that states have exclusive authority over resource planning and the \ngeneration mix within their boundaries.211  Nothing about our preliminary finding here, \nhowever, intrudes or is intended to intrude on that exclusive authority.  Rather, we \npreliminarily find that it is necessary and appropriate to exercise our exclusive \njurisdiction over generator interconnection to ensure the availability of generator \ninterconnection processes specifically tailored to the unique operational characteristics of \ngenerating facilities dedicated to serving electrically proximate large loads and co-located \nloads, as defined below.  The Commission has exercised this jurisdiction previously in \nrequiring generator interconnection services that allow certain generating facilities to \ninterconnect more quickly through the use of provisional interconnection service and \nsurplus interconnection service,212 and has approved interconnection processes that allow \n \n208 16 U.S.C. § 824(b)(1). \n209 Id.; Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d at 1280-82 \n(affirming Order No. 2003 and observing that “interconnections appear to be \nrelationships between parties with respect to electricity flowing over facilities. . . By \nestablishing standard agreements [the Commission] has exercised its jurisdiction over \nthe terms of those relationships.”); see Pac. Gas & Elec. Co., 115 FERC ¶ 61,193 at P 36 \n(“[I]interconnection is part and parcel of transmission of electric energy in interstate \ncommerce, and thus interconnection service is part and parcel of jurisdictional \ntransmission service.”).  \n210 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. \n211 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 (citing \n16 U.S.C. § 824(b)(1)).  \n212 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, \n163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order        \nNo. 845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B,       \n168 FERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; PJM \nInterconnection, L.L.C., 190 FERC ¶ 61,083 (2025)."},{"page":62,"startToken":24757,"endToken":25160,"text":"Docket No. EL26-67-000 \n- 62 - \ncertain generating facilities to interconnect more quickly by replacing a retiring existing \ngenerating facility.213   \n2. \nDefinitions \n \nFor purposes of this order, it appears to be reasonable to use the term “electrically \nproximate large load” to mean a large load, as defined in this order,214 that is sufficiently \nelectrically close to the interconnection customer’s requested point of interconnection, \nsuch that the impact on the transmission system of the combination of the generating \nfacility and the load, with the exception of the transmission facilities between the two, \nwill be effectively the same as if they were located at the same substation (e.g., large load \nthat is located no more than two substations away from the generating facility).  We will \nconsider proposed revisions to this definition that ensure it is appropriately tailored to \nPJM’s transmission system. \n3. \nTariff Provisions \n \nWe preliminarily find that PJM’s Tariff appears to be unjust and unreasonable \nbecause it does not contain provisions allowing an interconnection customer to seek the \ngenerator interconnection service(s) that reflects the operational dynamics of serving \neither:  (1) an electrically proximate large load; or (2) a co-located load, as defined in the \nPJM Co-Location Order,215 that has a high peak load (i.e., large co-located loads that are \n50 MW or greater).216  Specifically, we preliminarily find that PJM’s Tariff appears to be \nunjust and unreasonable because it lacks a generator interconnection study process and/or \ngenerator interconnection service to reflect an interconnection customer’s commitment in \nan interconnection agreement to limit the generating facility’s output to minimize the \nimpact on the transmission system while serving an electrically proximate large load or \nlarge co-located load.  We are concerned that PJM’s Tariff lacks, for example, generator \ninterconnection study procedures and generator interconnection services that reflect (a) \nan interconnection customer’s commitment in an interconnection agreement to limit a \ngenerating facility’s output to match the hourly forecast of an electrically proximate large \nload or large co-located load; and/or (b) a generating facility with necessary control \ntechnologies and/or protection systems, which may include a special protection \n \n213 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); \nMidcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019).  \n214 See supra P 58. \n215 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164. \n216 We note that generator interconnection service in and of itself does not convey \ntransmission service."},{"page":63,"startToken":25160,"endToken":25633,"text":"Docket No. EL26-67-000 \n- 63 - \nscheme,217 that ensure that the injection does not exceed the limit in the existing or new \ninterconnection agreement.  Where a generating facility’s output is matched to the \ndemand of the electrically proximate large load or large co-located load or if the \ngenerating facility’s output is limited to ensure no new injection, the impacts to the \ntransmission system of interconnecting the generating facility to serve that electrically \nproximate large load or large co-located load may be limited,218 thereby potentially \nreducing the need for Network Upgrades, which can accelerate the generator \ninterconnection process.219  In the absence of Tariff provisions accounting for these \noperational dynamics when an interconnection customer’s generating facility is serving \nelectrically proximate large loads or large co-located loads, new shovel-ready generating \nfacilities may face unnecessary delays in reaching commercial operation under current \ngenerator interconnection processes and will be unable to serve the immediate demand of \nnew large loads or large co-located loads.220    \n \n217 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n218 In other words, because the generating facility and load are located so closely \non the transmission system, if the generating facility’s output matches the load’s demand, \nthen the transmission provider would need to study only the local impacts because the \nimpact on the transmission system of the combination of the generating facility and the \nload, with the exception of the transmission facilities between the two, will be effectively \nthe same as if they were located at the same substation. \n219 See, e.g., AEU November 21 ANOPR Comments at 13 (“To the extent that a \nnew large load and new generation or storage resource are geographically and electrically \nproximate, studying them together would reduce network upgrades, lower costs, and \nreduce the need for critical supply chain components.”); DTE November 21 ANOPR \nComments at 10 (integrating the study of load and its supporting generation “reduces the \nneed for network upgrades, optimizes the use of existing infrastructure, and accelerates \nthe timeline for bringing both load and generation online”); Eolian November 21 ANOPR \nComments at 18 (“It is obvious from basic engineering principles that generation located \nnear load requires less transmission infrastructure to serve that load than generation \nlocated distant from load.”); GridStor November 21 ANOPR Comments at 5 (“Siting a \nlarge load near or at the same point of interconnection as a new generating facility could \nreduce the network upgrades needed to interconnect only the load or only the generating \nfacility.”).  \n220 See AEP December 5 ANOPR Comments at 1; Base Power November 21 \nANOPR Comments at 7; CEBA November 21 ANOPR Comments at 8; DCC            \nNovember 21 ANOPR Comments at 6 (asserting that a clear framework to study large \nloads paired with generation would resolve development bottlenecks); Eolian              \nNovember 21 ANOPR Comments at 18-19; Eolian May 19 ANOPR Comments at 2;"},{"page":64,"startToken":25633,"endToken":26040,"text":"Docket No. EL26-67-000 \n- 64 - \n \nAs commenters in the ANOPR proceeding have recognized, the status quo may \nresult in inefficient and unnecessary development of infrastructure, which leads to \nunnecessarily higher Network Upgrade costs that may result in unjust and unreasonable \nrates.221  The Commission has already determined in the PJM Co-Location Order that \nwithout the new transmission services that reflect the operational dynamics of co-location \narrangements, there could be unnecessary, costly, and inefficient Network Upgrades, \nincreasing Network Upgrade costs.222  The same result may occur in the absence of new \ngenerator interconnection study procedures and generator interconnection services \ntailored to a new generating facility coming online for the express purpose of serving an \nelectrically proximate large load or large co-located load.223    \n \nSPP recognized this problem and submitted an FPA section 205 filing to \nimplement a new, interim, generator interconnection service and related generator \ninterconnection process, HILLGA, to facilitate the prompt interconnection of generating \nfacilities that are specifically identified for and limited to serving a HILL, which the \nCommission accepted.224  The Commission found that HILLGA “reasonably provides a \nflexible, expedited, and separate serial interconnection process that will facilitate the \nprompt interconnection of generating facilities that are limited to serving a HILL in the \n \nGoogle November 21 ANOPR Comments at 7 (calling for nationwide rules enabling \nproximate load-generation interconnection to “accelerate the pace at which new \ngeneration comes online”); Longroad November 21 ANOPR Comments at 8. \n221 See, e.g., AEU November 21 ANOPR Comments at 13, AEP December 5 \nANOPR Comments at 1-2; Longroad November 21 ANOPR Comments at 8; OPSI \nNovember 21 ANOPR Comments at 11. \n222 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible \nCustomers taking service on behalf of Co-Located Loads that do not reserve \ntransmission . . . requiring such Eligible Customers to take NITS on behalf of these            \nCo-Located Loads may in some circumstances result in costly and inefficient \ntransmission system buildout that may not be necessary if such Eligible Customers are \nwilling and able to take a transmission service that requires fewer Network Upgrades to \nprovide, and therefore may result in lower Network Upgrade costs, than would NITS.”). \n223 See AEP December 5 ANOPR Comments at 1-2 (stating that current processes \nproduce insufficient/inefficient infrastructure and “potentially unsustainable price \nincreases”); Eolian May 19 ANOPR Comments at 2, 10 (contending that a lack of \ncoordinated study leads to unjust and unreasonable outcomes).  \n224 SPP HILL Order, 194 FERC ¶ 61,031."},{"page":65,"startToken":26040,"endToken":26455,"text":"Docket No. EL26-67-000 \n- 65 - \nsame local area.”225  We do not expect or propose that PJM adopt an identical process to \nSPP’s HILLGA process, nor do we preliminarily find that the absence of Tariff \nprovisions specifically mirroring SPP’s Tariff renders PJM’s Tariff unjust and \nunreasonable.  Nevertheless, we remain concerned that the Tariff may be unjust and \nunreasonable without any uniquely tailored interconnection study process and/or \ngenerator interconnection service to recognize the reduced transmission system impacts \nthat may result from the interconnection of a generating facility where the \ninterconnection customer has committed, in an interconnection agreement, to limit the \ngenerating facility’s output to match the hourly forecast of an electrically proximate large \nload or large co-located load.226  To the extent that the interconnection customer’s \ngenerating facility is serving an electrically proximate large load, we believe that the \ngenerator interconnection service should be of an interim nature until the interconnection \ncustomer obtains Energy Resource Interconnection Service (ERIS) or Network Resource \nInterconnection Service (NRIS).  To the extent that the interconnection customer’s \ngenerating facility is serving a large co-located load, it may be reasonable for the \ngenerator interconnection service to be permanent because there will be no injections \nonto the transmission system and therefore it does not present operational or planning \nrisks for reliability.   \n \nAnother potentially reasonable approach to address our concerns could be to \ndevelop a generator interconnection study process that would allow the use of existing \nERIS or NRIS of an existing generator to connect a new generating facility and a new \nlarge load behind the same point of interconnection of the existing generator with \nnecessary control technologies and/or protection systems, which may include a special \nprotection scheme, that ensure that the net injection does not exceed the amount in the \nexisting generator interconnection agreement.227  Such an approach could expedite the \ninterconnection study process for a generator planning to serve an electrically proximate \n \n225 Id. P 64. \n226 While, as discussed above, we view such a process that permits generation to \nserve electrically proximate loads no more than two substations away from the generators \nto be reasonable, we understand the unique features of PJM’s transmission system may \nwarrant consideration of a more limited definition of electrically proximate.  See Duke \nNovember 21 ANOPR Comments at 21-22; DTE November 21 ANOPR Comments               \nat 8-11 (asserting that studying large loads with electrically proximate generation \nstreamlines interconnection and reduces upgrades); AEU November 21 ANOPR \nComments at 13-15. \n227 See Constellation June 5 ANOPR Comments at 1-2, 10-13."},{"page":66,"startToken":26455,"endToken":26895,"text":"Docket No. EL26-67-000 \n- 66 - \n(in this case at the same point of interconnection) large load.228  An additional potentially \nreasonable approach could be a new load-limited generator interconnection service that \nallows a new generating facility and new large co-located load seeking to interconnect \nbehind the same new point of interconnection, with necessary control technologies and/or \nprotection systems, which may include a special protection scheme, to ensure that there is \nno injection to the transmission system.229  It may be reasonable for such a load-limited \ngenerator interconnection service to be or not to be of an interim nature.  We invite PJM \nand/or Transmission Owners, in responding to this order or in an FPA section 205 filing, \nto submit original proposals designed to address the concerns expressed herein and \ntailored to their unique circumstances.  \n \nWe are concerned that the absence of generator interconnection study procedures \nand generator interconnection services facilitating the interconnection of a new \ngenerating facility that is being brought onto the transmission system in order to serve an \nelectrically proximate large load or large co-located load will result in PJM’s current \ngenerator interconnection process failing to keep pace with the new large loads seeking to \nbe integrated onto PJM’s transmission system.230  We preliminarily find that this \noutcome may be unjust and unreasonable because reliance on PJM’s current generator \ninterconnection processes for generating facilities serving electrically proximate large \nloads or large co-located loads could result in unnecessary interconnection delays, \nunnecessary Network Upgrades, and an otherwise inefficient expansion of the \ntransmission system, imposing unnecessary delays and costs on transmission customers. \n PJM should explain whether the Tariff remains just and reasonable without, for \nexample, provisions that establish:  (1) a new generator interconnection study process and \nnew interim generator interconnection service that reflect an interconnection customer’s \n \n228 See id. at 5 (explaining that when new generation load pairings “are sited at an \nexisting generator’s Point of Interconnection and fall within the same study parameters \nreflected by that existing generator’s interconnection, they benefit from studies and \nupgrades already completed for that existing generator and can come on more rapidly \nwithout jeopardizing reliability”). \n229 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 \nANOPR Comments at 13-14.   \n230 See Helion November 21 ANOPR Comments at 1 (noting interconnection \ndelays are the biggest barrier to adding new generation); Oracle November 21 ANOPR \nComments at 1 (noting significant delays in access to sufficient energy for data centers); \nOPSI November 21 ANOPR Comments at 11 (explaining that expedited study \nencourages loads to bring their own generation); Enchanted Rock November 21 ANOPR \nComments at 4; Microsoft November 21 ANOPR Comments at 8-9."},{"page":67,"startToken":26895,"endToken":27346,"text":"Docket No. EL26-67-000 \n- 67 - \ncommitment, in a generator interconnection agreement, to limit a generating facility’s \noutput to match the hourly forecast of an electrically proximate large load or large               \nco-located load; or (2) a generator interconnection study process that allows the use of the \nexisting ERIS or NRIS of an existing generator to connect a new generating facility and a \nnew large load behind the same point of interconnection of the existing generator with \nnecessary control technologies and/or protection systems, which may include a special \nprotection scheme, that ensures that the net injection does not exceed the amount in the \nexisting generator interconnection agreement; or (3) a new generator interconnection \nservice that allows a new generating facility and new large co-located load seeking to \ninterconnect behind the same new point of interconnection with necessary control \ntechnologies and/or protection systems, which may include a special protection scheme, \nto ensure that there is no injection to the transmission system.  We note that, with respect \nto numbers (2) or (3), these approaches could be either interim or permanent.  These \napproaches may not be mutually exclusive. \n Given that generator interconnection service in and of itself does not convey \ntransmission service, we encourage PJM to consider, in responding to these concerns, \nwhat type of transmission service an Eligible Customer will need to take on behalf of the \nelectrically proximate large load or large co-located load.231  We note that, in the PJM \nCo-Location Order, the Commission found that the Eligible Customer must take \ntransmission service on behalf of co-located load that will not withdraw energy from the \ntransmission system, even if it is 0 MW.232 \nE. \nInformational Report \n The rapid addition and proliferation of large loads without commensurate \nadditions of supply or demand-side resources presents resource adequacy concerns.  As \ndiscussed above and highlighted in the ANOPR, the growth of demand, and the speed of \nsuch growth, is driven in large part by the interconnection of large loads.  While not \nexpressly contemplated in the ANOPR, commenters highlight the strain rapid demand \ngrowth is putting on resource adequacy in many regions.233  Indeed, the relative speed \nand concentration at which large loads are seeking to interconnect appears to be \noutpacing the addition of new generation, which in turn heightens reliability risks and \n \n231 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. \n232 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. \n233 See, e.g., Entergy November 21 ANOPR Comments at 29-30; Eolian \nNovember 21 ANOPR Comments at 16-17; Industrial Customers November 21 ANOPR \nComments at 24-26; R Street November 21 ANOPR Comments at 1; South Dakota \nCommission November 13 ANOPR Comments at 5; Talen December 5 ANOPR \nComments at 7."},{"page":68,"startToken":27346,"endToken":27789,"text":"Docket No. EL26-67-000 \n- 68 - \ndrives up costs to ratepayers.234  We are concerned that PJM and load serving entities are \nunable to plan adequate generation to serve all load at the pace such load seeks to \nconnect.   \n We recognize that RTOs/ISOs are engaging in efforts to more rapidly interconnect \ngeneration that is needed to serve this unprecedented growth in load.  In particular, PJM’s \nReliability Resource Initiative and Expedited Interconnection Track have provided \npathways for expedited interconnection for generation.235  Further, as detailed above and \nin informational reports submitted by PJM,236 PJM has ongoing stakeholder processes to \naddress resource adequacy issues related to large load additions, including a voluntary \n“Bring Your Own New Generation” pathway for large loads, a “connect-and-manage” \nframework applicable to new large loads that do not bring commensurate new generating \ncapacity, and a reliability backstop procurement.237  While we are encouraged by the \nimplementation of such processes to ensure resource adequacy and faster interconnection \nand ongoing stakeholder discussions, we remain concerned that these efforts may fall \nshort in light of generator retirements and tightening supply conditions. \n Accordingly, we direct PJM to submit in Docket No. EL26-67-000, within 30 days \nof the date of issuance of this order, a detailed informational report on the current status \nof proposals under consideration in its stakeholder process to address the issue of \nresource adequacy to serve new large loads.  We also strongly encourage new proposals \nto the extent necessary to address these concerns.  The informational report must include \na detailed schedule of key milestones, such as stakeholder or PJM Board votes, that \nincludes the estimated date on which PJM expects to file any such proposals with the \nCommission.  Additionally, as part of this informational report, we direct PJM to identify \nany problem statements, issue charges, or other ongoing stakeholder processes that aim to \nincrease the pace of adding generating capacity in the PJM region.  The informational \n \n234 See, e.g., Eolian November 21 ANOPR Comments at 16-17; David Gardiner & \nAssociates November 21 ANOPR Comments at 1-2; Joint Consumer Advocates \nDecember 5 ANOPR Comments at 2; PSEG November 21 ANOPR Comments at 8; \nSouthern California Edison December 5 ANOPR Comments at 3. \n235 PJM Interconnection, L.L.C., 190 FERC ¶ 61,084; order on reh’g, 192 FERC \n¶ 61,085 (2025); PJM EIT Order, 195 FERC ¶ 61,197. \n236 PJM Interconnection, L.L.C., Informational Report, Docket No. EL25-49-000,  \net al. (filed Jan. 20, 2026); PJM Interconnection, L.L.C., Supplemental Informational \nReport, Docket No. EL25-49-000, et al. (filed Feb. 23, 2026); PJM Interconnection, \nL.L.C., Second Supplemental Informational Report, Docket No. EL25-49-000, et al. \n(filed Mar. 9, 2026). \n237 See supra P 33."},{"page":69,"startToken":27789,"endToken":28223,"text":"Docket No. EL26-67-000 \n- 69 - \nreport must include a detailed schedule of such initiatives, including timing of the \nstakeholder process and dates of any anticipated filings with the Commission.   \nIV. \nBriefing Questions \n We note that large loads, including data centers, are actively working with \ntransmission owners and other relevant entities to interconnect to, and to take \ninterconnection and/or transmission service from, the transmission system and may be at \nvarying stages of that process.  We appreciate that different large loads are currently at \ndifferent stages of that process.  We also understand that large loads and Eligible \nCustomers taking transmission service on behalf of large loads are negotiating, entering \ninto, and/or have executed various agreements related to interconnecting to the \ntransmission system and/or the provision of transmission service.  We direct further \nbriefing regarding how PJM and the Transmission Owners, in responding to the order to \nshow cause, should protect existing commercial arrangements including:  (1) what would \nbe a reasonable implementation period to ensure minimal disruption to such existing \ncommercial arrangements, and (2) how to allow a reasonable amount of time to finalize \nongoing agreements that are nearing completion as of the date such Tariff provisions are \nfiled with the Commission.  \n Today’s order proposes, as part of a potential replacement rate, to establish new \ntransmission services that recognize flexible large loads’ ability and willingness to limit \ntheir use of the transmission system under certain conditions.  As we assess this proposal, \nwe also consider how these new transmission services might affect other parts of PJM’s \nTariff and/or processes.  Specifically, what, if any, potential impacts on regional and \nlocal transmission planning would arise from the introduction of the new transmission \nservices discussed herein?  For example, when planning for load growth, how would \ntransmission providers and planners account for flexible large loads’ potential preference \nto take the new transmission services, including potential uncertainties around the type, \nlocation, and quantity of such expected loads?     \n Today’s order preliminarily finds that PJM’s Tariff appears to be unjust and \nunreasonable without the inclusion of cost shifting protections.  We find that there may \nbe a variety of possible approaches to protect customers from significant cost shifts \nassociated with Network Upgrades triggered by large loads.  To that end, we direct \nrespondents to include information regarding potential structures for agreements between \nthe transmission owner/provider and an Eligible Customer to prevent unjust and \nunreasonable cost shifts among transmission customers related to Network Upgrade costs \nrequired for large loads.  Further, please include information on what an appropriate \nminimum level of cost recovery and financial security from an Eligible Customer would \nbe under any such agreements."},{"page":70,"startToken":28223,"endToken":28629,"text":"Docket No. EL26-67-000 \n- 70 - \n Today’s order preliminarily finds that PJM’s Tariff appears to be unjust and \nunreasonable because it lacks clear and consistent provisions requiring the evaluation of \nalternative transmission technologies.  The order directs PJM to explain whether the \nTariff remains just and reasonable without provisions that:  (1) require the evaluation of \nalternative transmission technologies in transmission service request studies, using \nmodels that are capable of evaluating the transmission system to accurately account for \nadvanced transmission technologies, in all instances, without the need for a request from \nthe Eligible Customer seeking transmission service on behalf of large load; and (2) if \ntraditional Network Upgrades are selected instead of alternative transmission \ntechnologies, inclusion in the study report to the Eligible Customer seeking transmission \nservice on behalf of large load of a sufficiently clear demonstration of why alternative \ntransmission technologies are not feasible (i.e., would not resolve reliability violations \nidentified or meet the relevant planning criteria) or would not result in lower costs or a \nfaster timeline for accommodating the transmission service request.  As noted above, to \nthe extent stakeholders believe that specific characteristics of providing transmission \nservice to Eligible Customers on behalf of large loads warrant requirements beyond those \ncontemplated here, we seek further briefing. \n Today’s order preliminarily finds that PJM’s Tariff appears to be unjust and \nunreasonable because it does not contain provisions allowing an interconnection \ncustomer serving electrically proximate large load or large co-located load to seek \ngenerator interconnection service(s) that reflects the operational dynamics of serving such \nloads.  Any filings or tariff changes submitted in response to this order should address the \nfollowing questions:  \na. To what extent would PJM allow an interconnection customer’s generating \nfacility serving electrically proximate large load or large co-located load to \nparticipate in PJM’s energy and ancillary services market, and if PJM were \nto allow them to participate, what restrictions or mitigation would PJM \napply? \nb. To the extent that PJM plans for the electrically proximate large load or \nlarge co-located load associated with an interconnection customer’s \ngenerating facility for resource adequacy purposes, would PJM account for \nthe generating facilities serving electrically proximate large load or large \nco-located load in the resource adequacy construct?  If applicable, would \nPJM allow the generating facilities serving electrically proximate large load \nor large co-located load to participate in PJM’s capacity market?  If so, \nwould PJM accredit these generating facilities using the same method as \nother PJM generating facilities? \nThe Commission orders:"},{"page":71,"startToken":28629,"endToken":29090,"text":"Docket No. EL26-67-000 \n- 71 - \n(A) \nPursuant to the authority contained in and subject to the jurisdiction \nconferred upon the Federal Energy Regulatory Commission by section 402(a) of the \nDepartment of Energy Organization Act and by the FPA, particularly section 206 thereof, \nand pursuant to the Commission’s Rules of Practice and Procedure and the regulations \nunder the FPA (18 C.F.R. Chapter I), the Commission hereby institutes a proceeding in \nDocket No. EL26-67-000 as discussed in the body of this order. \n(B) \nPJM and the Transmission Owners are hereby directed, within 60 days of \nthe date of the order, either:  (1) to show cause as to why the Tariff remains just and \nreasonable and not unduly discriminatory or preferential; or (2) to explain what changes \nto the Tariff they believe would remedy the identified concerns if the Commission were \nto determine that the Tariff has in fact become unjust and unreasonable or unduly \ndiscriminatory or preferential and, therefore, proceeds to establish a replacement Tariff. \n(C) \nPJM is directed to submit an informational report within 30 days of the date \nof issuance of this order, as discussed in the body of this order. \n(D) \nAny interested person desiring to be heard in Docket No. EL26-67-000 \nmust file a notice of intervention or motion to intervene, as appropriate, with the          \nFederal Energy Regulatory Commission, 888 First Street, NE, Washington, DC  20426, \nin accordance with Rule 214 of the Commission’s Rules of Practice and Procedure,           \n18 C.F.R. § 385.214 (2025), within 21 days of the date of issuance of this order.  The \nCommission encourages electronic submission of interventions in lieu of paper using the \n“eFiling” link at http://www.ferc.gov.  Persons unable to file electronically may file by \nU.S. mail addressed to Federal Energy Regulatory Commission, Secretary of the \nCommission, 888 First Street, N.E., Washington, DC  20426, or by hand (including \ncourier) delivery to Federal Energy Regulatory Commission, 12225 Wilkins Avenue, \nRockville, MD  20852. \n(E) \nInterested entities may respond within 30 days of PJM’s and the \nTransmission Owners’ filing, addressing either or both of:  (1) whether the Tariff remains \njust and reasonable and not unduly discriminatory or preferential; and (2) if not, what \nchanges to the Tariff should be implemented as a replacement rate. \n(F) \nThe Secretary shall promptly publish in the Federal Register a notice of the \nCommission’s initiation of the proceeding under section 206 of the FPA in Docket               \nNo. EL26-67-000. \n(G) \nThe refund effective date in Docket No. EL26-67-000 pursuant to               \nsection 206 of the FPA shall be the date of publication in the Federal Register of the \nnotice discussed in Ordering Paragraph (F) above. \nBy the Commission.  Chairman Swett is concurring with a separate statement attached. \n \n \n \n  Commissioner Rosner is concurring with a separate statement"},{"page":72,"startToken":29090,"endToken":29130,"text":"Docket No. EL26-67-000 \n- 72 - \n \n \n \n  attached. \n \n \n \n  Commissioner See is concurring with a separate statement attached. \n \n \n \n  Commissioner Chang is concurring with a separate statement \n  \n \n \n  attached. \n \n \n \n  Commissioner LaCerte 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 \n \nDebbie-Anne A. Reese, \nSecretary."},{"page":73,"startToken":29130,"endToken":29363,"text":"Docket No. EL26-67-000 \n- 73 - \nAppendix - Commenters in Docket No. RM26-4-000 \n \nAdvanced Energy Management Alliance (AEMA) \nAdvanced Energy United (AEU) \nAdvancing Modern Powerlines Coalition (together with Working for Advanced \nTransmission Technologies Coalition, WATT and Advancing Modern Powerlines) \nAdvocates for Consumer Regulated Electricity \nAES Corporation (AES) \nAI Supply Chain Alliance \nAlexandre Figueras, on behalf of Monza Tech \nAlliance for Tribal Clean Energy \nAlliant Energy Corporate Services, Inc. \nAmazon Energy LLC (Amazon) \nAmerica’s Power  \nAmerican Chemistry Council  \nAmerican Clean Power Association  \nAmerican Conservation Coalition \nAmerican Council on Renewable Energy (ACORE) \nAmerican Electric Power Service Corporation238 \nAmerican Public Gas Association \nAmerican Public Power Association (APPA) \nAmerican Terawatt, Inc. (American Terawatt) \nAmerican Transmission Company LLC239 \nAmericans for a Clean Energy Grid \nAntora Energy, Inc.  \nArevia Power \nArizona Public Service Company \nArkansas Public Service Commission \nAttorney General of the State of Oklahoma \n \n238 American Electric Power Service Corporation submitted comments on behalf \nof its affiliates Appalachian Power Company, Indiana Michigan Power Company, \nKentucky Power Company, Kingsport Power Company, Ohio Power Company, \nWheeling Power Company, Public Service Company of Oklahoma, Southwestern \nElectric Power Company, AEP Appalachian Transmission Company, Inc., AEP Indiana \nMichigan Transmission Company, Inc., AEP Kentucky Transmission Company, Inc., \nAEP Ohio Transmission Company, Inc., AEP West Virginia Transmission Company, \nInc., AEP Oklahoma Transmission Company, Inc., and AEP Southwestern Transmission \nCompany, Inc. \n239 American Transmission Company LLC submitted comments on behalf of itself \nand its corporate manager ATC Management Inc."},{"page":74,"startToken":29363,"endToken":29563,"text":"Docket No. EL26-67-000 \n- 74 - \nBase Power Company, Inc (Base Power). \nBloom Energy Corporation \nBuckeye Power, Inc. (Buckeye) \nCalibrant Energy Holdings, LLC (Calibrant) \nCalifornia Department of Water Resources State Water Project (California DWR) \nCalifornia Independent System Operator Corporation \nCalifornia Public Utilities Commission (CPUC) \nCenter for Biological Diversity \nChevron U.S.A., Inc. \nClean Energy Buyers Association (CEBA) \nClearPath, Inc. (ClearPath) \nConfederated Tribes and Bands of the Yakama Nation \nConstellation Energy Generation, LLC (Constellation) \nConsumer Energy Alliance \nConsumers Energy Company \nCritical Loop, Inc. (Critical Loop) \nCrusoe Energy Systems, Inc. (Crusoe) \nCTC Global Corporation \nData Center Coalition (DCC) \nDavid Gardiner & Associates  \nDelaware Division of the Public Advocate (together with Pennsylvania Office of  \nConsumer Advocate, Joint Consumer Advocates)240 \nDigital Energy Council  \nDigital Power Network \nDistributed Capacity Parties241 \nDr. Elisa Nelson \nDTE Electric Company (DTE) \nDuke Energy Corporation (Duke) \nEDF Power Solutions, Inc. (EDF Power) \nEdison Electric Institute (EEI) \nElectricity Consumers Resource Council (ELCON) \nElectricity Customers Alliance (ECA) \nElectric Power Supply Association (EPSA) \nEmerald AI (Emerald) \nEnchanted Rock, LLC  \nEnergy New England, LLC \n \n240 The Illinois Attorney General joined the Joint Consumer Advocates in filing \nreply comments. \n241 Distributed Capacity Parties include:  Cloverleaf Infrastructure; Spark \nCommunity Investment d/b/a Sparkfund; and Voltus, Inc."},{"page":75,"startToken":29563,"endToken":29789,"text":"Docket No. EL26-67-000 \n- 75 - \nEnergy Trading Institute \nENGIE North America, Inc. (ENGIE) \nEntergy Services, LLC (Entergy)242 \nEnvironmental Law & Policy Center \nEolian L.P. (Eolian) \nEquinix, Inc. \nesVolta, LP \nETX Upstream, LLC \nEversource Energy243 \nExelon Corporation (Exelon)244 \nFervo Energy Company (Fervo) \nFirstEnergy Service Company245 \nFluence \nFront Door Technologies LLC \nFuelCell Energy, Inc. \nGeorgia Public Service Commission  \nGeronimo Power, LLC (Geronimo) \nGoogle LLC (Google) \nGovernors Josh Shapiro and Glenn Youngkin \nGridCARE \nGridStor LLC (GridStor) \nHarvard Electricity Law Initiative \n \n242 Entergy submitted comments on behalf of the Entergy Operating Companies, \nwhich include Entergy Arkansas, LLC, Entergy Louisiana, LLC, Entergy Mississippi, \nLLC, Entergy New Orleans, LLC, and Entergy Texas, Inc. \n243 Eversource Energy submitted comments on behalf of its affiliates The \nConnecticut Light and Power Company, NSTAR Electric Company, and Public Service \nCompany of New Hampshire, and through its agent Eversource Energy Service \nCompany. \n244 Exelon submitted comments on behalf of itself and its affiliates Atlantic City \nElectric Company, Baltimore Gas and Electric Company, Commonwealth Edison \nCompany, Commonwealth Edison Company of Indiana, Inc., Delmarva Power and Light \nCompany, PECO Energy Company, and Potomac Electric Power Company. \n245 FirstEnergy Service Company submitted comments on behalf of itself and its \naffiliates American Transmission Systems, Inc., 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."},{"page":76,"startToken":29789,"endToken":30107,"text":"Docket No. EL26-67-000 \n- 76 - \nHelion Energy (Helion) \nHerbert Schrayschuen \nHeron Power Electronics Company  \nIndiana Energy Association \nIndicated PJM Transmission Owners (PJM TOs)246 \nIndustrial Customer Organizations (Industrial Customers)247 \nInformation Technology Industry Council \nInfrastructure Masons, Inc. (Infrastructure Masons) \nInstitute for Progress \nInternational Energy Credit Association \nInvenergy248 \nIron Mountain Data Centers, LLC \n \n246 PJM TOs include:  AEP on behalf of Appalachian Power Company, Indiana \nMichigan Power Company, Kentucky Power Company, Kingsport Power Company, \nOhio Power Company, Wheeling Power Company, AEP Appalachian Transmission \nCompany, Inc., AEP Indiana Michigan Transmission Company, Inc., AEP Kentucky \nTransmission Company, Inc., AEP Ohio Transmission Company, Inc., and AEP West \nVirginia Transmission Company, Inc.; AMP Transmission, LLC; City of Cleveland, \nDepartment of Public Utilities, Division of Cleveland Public Power; City of Hamilton, \nOH; Dominion Energy Services, Inc. on behalf of Virginia Electric and Power Company \nd/b/a Dominion Energy Virginia; Duke Energy Corporation on behalf of its affiliates \nDuke Energy Ohio, Inc., Duke Energy Kentucky, Inc., and Duke Energy Business \nServices LLC; Duquesne Light Company; East Kentucky Power Cooperative; Exelon \nCorporation, on behalf of Atlantic City Electric Company, Baltimore Gas and Electric \nCompany, Commonwealth Edison Company, Commonwealth Edison Company of \nIndiana, Inc., Delmarva Power & Light Company, PECO Energy Company, and Potomac \nElectric Power Company; 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 Trans-\nAllegheny Interstate Line Company; Old Dominion Electric Cooperative; PPL Electric \nUtilities Corporation; Rockland Electric Company; Southern Maryland Electric \nCooperative, Inc.; UGI Utilities Inc; and Wabash Valley Power Association, Inc. \n247 Industrial Customers include:  the Industrial Energy Consumers of America, \nthe American Forest & Paper Association, the PJM Industrial Customer Coalition, and \nthe Coalition of MISO Transmission Customers \n248 Invenergy includes:  Invenergy Wind Development North America LLC, \nInvenergy Solar Development North America LLC, and Invenergy Thermal Development \nHoldings LLC."},{"page":77,"startToken":30107,"endToken":30389,"text":"Docket No. EL26-67-000 \n- 77 - \nISO New England, Inc. \nITC Holdings Corp. (ITC) \nJason Miller, on behalf of VEIR Inc. \nKansas Corporation Commission (Kansas Commission) \nL. Lynne Kiesling \nL.M. Marlowe \nLand Trust Alliance \nLarge Public Power Council \nLauren Hopkins \nLEAN Energy US \nLoad Flexibility Parties249 \nLong Island Power Authority \nLongroad Energy Holdings, LLC (Longroad) \nLouisiana Public Service Commission  \nLS Power Development, LLC (LS Power) \nMaine Office of the Public Advocate \nMaryland Energy Administration  \nMaryland Public Service Commission (Maryland Commission) \nMaven Solutions  \nMCC Economics and Finance \nMeta Platforms, Inc. \nMichigan Attorney General Dana Nessel \nMicrosoft, Inc. (Microsoft) \nMidcontinent Independent System Operator, Inc. \nMISO Transmission Owners (MISO TOs)250 \n \n249 Load Flexibility Parties include:  Enerwise Global Technologies, LLC d/b/a \nCPower, Enel North America, Inc., and Voltus, Inc. \n250 MISO TOs include:  Ameren Services Company, as agent for Union Electric \nCompany d/b/a Ameren Missouri, Ameren Illinois Company d/b/a Ameren Illinois and \nAmeren Transmission Company of Illinois; American Transmission Company LLC; Big \nRivers Electric Corporation; Central Minnesota Municipal Power Agency; Citizens \nElectric Corporation; City Water, Light & Power (Springfield, IL); Cleco Power LLC; \nCooperative Energy; Dairyland Power Cooperative; Duke Energy Business Services, \nLLC for Duke Energy Indiana, LLC; East Texas Electric Cooperative; Entergy Arkansas, \nLLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy New Orleans, LLC; \nEntergy Texas, Inc.; Great River Energy; GridLiance Heartland LLC; Hoosier Energy \nRural Electric Cooperative, Inc.; Indiana Municipal Power Agency; Indianapolis Power \n& Light Company d/b/a AES Indiana; Lafayette Utilities System; MidAmerican Energy \nCompany; Minnesota Power (and its subsidiary Superior Water, L&P); Montana-Dakota \nUtilities Co.; Northern Indiana Public Service Company LLC; Northern States Power \nCompany, a Minnesota corporation, and Northern States Power Company, a Wisconsin"},{"page":78,"startToken":30389,"endToken":30671,"text":"Docket No. EL26-67-000 \n- 78 - \nMississippi Public Service Commission  \nMissouri Public Service Commission (Missouri Commission) \nMonitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor for \nPJM (PJM IMM) \nNathan Peterson \nNational Association of Regulatory Utility Commissioners  \nNational Association of State Utility Consumer Advocates \nNational Conference of State Legislatures (NCSL) \nNational Congress of American Indians \nNational Grid PLC (National Grid)251 \nNational Rural Electric Cooperative Association (NRECA) \nNebraska Power Review Board (Nebraska Board) \nNew England States Committee on Electricity \nNew England Conference of Public Utility Commissioners \nNew England Consumer-Owned Systems252  \n \ncorporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric \nCompany; Otter Tail Power Company; Prairie Power, Inc.; Republic Transmission, LLC; \nSouthern Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a \nCenterPoint Energy Indiana South); Southern Minnesota Municipal Power Agency; \nWabash Valley Power Association, Inc.; and Wolverine Power Supply Cooperative, Inc \n251 National Grid submitted comments behalf of its affiliates:  Niagara Mohawk \nPower Corporation; New England Power Company; New England Electric Transmission \nCorporation; New England Hydro-Transmission Corporation; New England                   \nHydro-Transmission Electric Company, Inc.; and Massachusetts Electric Company. \n252 New England Consumer-Owned Systems include:  Belmont Municipal Light \nDepartment, Block Island Utility District, Braintree Electric Light Department, Concord \nMunicipal Light Plant, Danvers Electric Division, Georgetown Municipal Light \nDepartment, Groveland Electric Light Department, Hingham Municipal Lighting Plant, \nHudson Light & Power Department, Littleton Electric Light & Water Department, \nMerrimac Municipal Light Department, Middleborough Gas & Electric Department, \nMiddleton Electric Light Department, North Attleborough Electric Department, Norwood \nMunicipal Light Department, Clear River Electric & Water District, Rowley Municipal \nLighting Plant, Stowe Electric Department, Taunton Municipal Lighting Plant, Town of \nWallingford, Connecticut Department of Public Utilities Electric Division, Westfield Gas \nand Electric Light Department, and Mid-Coast Regional Redevelopment Authority."},{"page":79,"startToken":30671,"endToken":30910,"text":"Docket No. EL26-67-000 \n- 79 - \nNew England Public Systems253 \nNew Mexico Public Regulation Commission (New Mexico Commission) \nNew York Independent System Operator, Inc. \nNew York State Department of State Utility Intervention Unit (NY UIU) \nNew York Public Service Commission \nNew York State Reliability Council \nNew York Transmission Owners254 \nNorth American Electric Reliability Corporation \nNorth Carolina Utilities Commission \nNorth Carolina Utilities Commission Public Staff \nNorth Dakota Public Service Commission \nNortheastern Rural Electric Membership Corporation \nNRG Energy, Inc. \nOffice of the Illinois Attorney General (Illinois AG) \nOffice of the Ohio Consumers’ Counsel (OCC) \nOklahoma Corporation Commission \nOklo Inc. (Oklo) \nOld Dominion Electric Cooperative (ODEC) \nOncor Electric Delivery Company LLC \nON Energy Storage, Inc. \nOpenAI Inc. \nOracle America, Inc. (Oracle) \nOrganization of MISO States, Inc. (OMS) \nOrganization of PJM States, Inc. (OPSI) \nPaces AI Inc. \nPacific Gas & Electric Company \nPaige Lambermont, on behalf of Competitive Enterprise Institute \nPaul Statchen \nPennsylvania Office of Consumer Advocate \nPennsylvania Public Utility Commission (Pennsylvania Commission) \nPew Charitable Trusts Energy Modernization Project \nPJM Interconnection, LLC (PJM) \n \n253 New England Public Systems include:  Connecticut Municipal Electric \nCooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont \nPublic Power Supply Authority. \n254 New York Transmission Owners include:  Central Hudson Gas & Electric \nCorporation, Consolidated Edison Company of New York, Inc., New York Power \nAuthority, New York State Electric & Gas Corporation, Niagara Mohawk Power Corp. \n(d/b/a National Grid), Orange and Rockland Utilities, Inc., Long Island Power Authority, \nand Rochester Gas and Electric Corporation."},{"page":80,"startToken":30910,"endToken":31157,"text":"Docket No. EL26-67-000 \n- 80 - \nPower for Tomorrow \nPPL Corporation255 \nPrime Mover Institute \nPSEG Companies (PSEG)256 \nPublic Citizen, Inc. \nPublic Interest Organizations (PIOs)257 \nPublic Utilities Commission of Ohio’s Office of the Federal Energy Advocate (Ohio  \nFEA) \nR Street Institute (R Street) \nRewiring America \nMCC Economics Ltd. \nRWE Clean Energy, LLC \nSarah McKinley \nShell Energy North America (US), L.P. \nSierra Club \nSMA Solar Technology AG \nSolar Energy Industries Association \nSouth Carolina Office of Regulatory Staff \nSouth Dakota Public Utilities Commission (South Dakota Commission) \nSoutheast Public Interest Organizations (Southeast PIOs)258 \nSouthern California Edison Company (Southern California Edison) \nSouthern Companies259 \n \n255 PPL Corporation submitted comments on behalf of the PPL Companies, which \ninclude PPL Electric Utilities Corporation, Louisville Gas & Electric Company and \nKentucky Utilities, and The Narragansett Electric Company d/b/a Rhode Island Energy. \n256 PSEG Companies include:  Public Service and Gas Company, PSEG Power \nLLC, and PSEG Energy Resources & Trade LLC, which are each wholly-owned, direct \nor indirect subsidiaries of Public Service Enterprise Group Incorporated. \n257 PIOs include:  Clean Air Task Force, Inc., Coalition for Affordable Utility \nServices and Energy Efficiency in Pennsylvania, Earthjustice, Environmental Defense \nFund, Montana Environmental Information Center, Natural Resources Defense Council, \nSustainable FERC Project, Sierra Club, and Southern Environmental Law Center. \n258 Southeast PIOs include:  Southern Environmental Law Center, Appalachian \nVoices, North Carolina Sustainable Energy Association, South Carolina Coastal \nConservation League, and Southern Alliance for Clean Energy. \n259 Southern Companies include:  Georgia Power Company, Alabama Power \nCompany, and Mississippi Power Company."},{"page":81,"startToken":31157,"endToken":31411,"text":"Docket No. EL26-67-000 \n- 81 - \nSouthern Maryland Electric Cooperative, Inc. \nSouthwest Power Pool, Inc. \nSouthwest Power Pool Transmission Owner Group260 \nSplight Inc. (Splight) \nState Entities261 \nSteel Manufacturers Association \nSwitch, Ltd. (Switch) \nTalen Energy Corporation (Talen) \nTerraflux LLC (Terraflux) \nTesla, Inc. \nTexas Blockchain Council \nThermal Battery Alliance \nTract Holding Company I, LLC (Tract) \nTransmission Access Policy Study Group (TAPS) \nTri-State Generation and Transmission Association, Inc. (Tri-State) \nTravis Fisher, on behalf of Cato Institute \nU.S. Chamber of Commerce (Chamber of Commerce) \nU.S. Energy Storage Coalition \nU.S. House of Representatives Committee on Energy and Commerce Ranking  \nMembers262 \nU.S. Representatives263 \nU.S. Senate Committee on Energy and Natural Resources \n \n260 Southwest Power Pool Transmission Owner Group includes:  American \nElectric Power Service Corporation, Evergy Kansas Central, Inc., Evergy Metro, Inc., \nEvergy Missouri West, Inc., Oklahoma Gas and Electric Company, and Xcel Energy \nServices Inc., on behalf of Southwestern Public Service Company. \n261 State Entities include:  Massachusetts Attorney General’s Office, the Arizona \nAttorney General’s Office, the Colorado Attorney General’s Office, the Connecticut \nOffice of Consumer Counsel, the Maryland Office of People’s Counsel, the Minnesota \nAttorney General’s Office, the Office of the Nevada Attorney General, Bureau of \nConsumer Protection, the New Hampshire Office of the Consumer Advocate, the Oregon \nAttorney General, and the Rhode Island Division of Public Utilities and Carriers. \n262 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking \nMember, Subcommittee on Energy). \n263 The U.S. Representatives that submitted comments include:  Suhas \nSubramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr."},{"page":82,"startToken":31411,"endToken":31482,"text":"Docket No. EL26-67-000 \n- 82 - \nU.S. Senators264 \nU.S. Senator Jon Ossoff \nUnion of Concerned Scientists (UCS) \nVantage Data Centers (Vantage) \nVerrus \nVirginia State Corporation Commission (Virginia Commission)  \nVistra Corp. (Vistra) \nWashington Utilities and Transportation Commission \nWIRES \nWisconsin Electric Company \nWisconsin Public Service Corporation  \n \n \n \n264 The U.S. Senators that submitted comments include:  Edward J. Markey, Chris \nVan Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and \nAdam B. Schiff."},{"page":83,"startToken":31482,"endToken":31658,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C.  \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. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAppalachian Power Company \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nDayton Power and Light Company \nDelmarva Power & Light Company \nDuke Energy Kentucky, Inc. \nDuke Energy Ohio, Inc. \nDuquesne Light Company \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nIndiana Michigan Power Company \nJersey Central Power & Light Company \nKentucky Power Company \nKeystone Appalachian Transmission Company \nKingsport Power Company \nLinden VFT, LLC \nMid-Atlantic Interstate Transmission, LLC \nMonongahela Power Company \nNeptune Regional Transmission System, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nOhio Power Company \nOhio Valley Electric Corporation \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nThe Potomac Edison Company \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nDocket No. EL26-67-000"},{"page":84,"startToken":31658,"endToken":32013,"text":"Docket No. EL26-67-000  \n \n- 2 - \n \n \nSilver Run Electric, LLC \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nVirginia Electric and Power Company \nWabash Valley Power Association, Inc. \nWheeling Power Company \n \n(Issued June 18, 2026) \n \nSWETT, Chairman, concurring: \n \n \nToday, we take historic action to push our country’s electric markets and economy \ninto the future—a future of fair cost allocation, unprecedented transparency for the \nAmerican ratepayer, respect for states’ rights, efficient markets and speed to power.  Last \nOctober, Secretary Wright articulated the monumental, generational and “urgent” \nchallenge FERC must solve for our country when he directed us to develop “reforms to \nensure the timely and orderly interconnection of large loads to the transmission system.”1  \nI strongly agree.  And now, through this suite of six orders, we deliver.     \n \nSimply put, the show cause orders the Commission issues today to each of the six \nelectric markets subject to its jurisdiction find that the status quo across much of the \ncountry is not good enough.2  Nowhere close.  The record prompted by the Secretary’s \nANOPR leaves no doubt that most of the markets (and their existing rules) are inherently \nslow and prohibitive of the dexterity necessary to adapt to and power societal evolution—\nwhether brought about by technological innovation or sustaining the great industrial \neconomy that anchors America.     \n \nI wholeheartedly, fully concur with these orders, which we carefully crafted to \nexecute upon the problems the Secretary identified in a manner that is quick, efficient, \n \n1 Advance notice of proposed rulemaking (ANOPR) Interconnection of Large \nLoads to the Interstate Transmission System, Advance Notice of Proposed Rulemaking \n(Oct. 23, 2025) (ANOPR); see Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy \n(Oct. 23, 2025) (Secretary’s Letter). \n2 Cal. Indep. Sys. Operator Corp., 195 FERC ¶ 61,214 (2026) (CAISO); ISO New \nEng. Inc., 195 FERC ¶ 61,215 (2026) (ISO-NE); Midcontinent Indep. Sys. Operator, Inc., \n195 FERC ¶ 61,212 (2026) (MISO); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 \n(2026) (NYISO); PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 (2026) (PJM); Sw. \nPower Pool, Inc., 195 FERC ¶ 61,213 (2026) (SPP) (collectively, Orders to Show \nCause)."},{"page":85,"startToken":32013,"endToken":32442,"text":"Docket No. EL26-67-000  \n \n- 3 - \n \n \nand legally durable.  I write separately to highlight certain considerations underlying the \nCommission’s procedural approach to delivering on the ANOPR and to today’s orders.   \n \nBased on my analysis of the extensive record and numerous ongoing substantive \nstakeholder interactions, I have determined that the most productive way to “build upon \nthe[] principles”3 in the ANOPR and “work expeditiously”4 towards a solution is to issue \nindividualized orders to show cause to each market.5  That is so for two main reasons. \n \nFirst, the record the Commission collected in response to the challenges identified \nin the ANOPR and subsequent resulting developments indicate that an approach that \nhonors the ANOPR principles but accounts for widening regional variation may now be \nmore efficient than a one-size-fits-all rule.6  The world has changed a great deal since last \nOctober.  The ANOPR itself, including the articulated principles, appears to have shifted \nthe playing field and prompted great progress across several electric markets.  This \nchange (and the Commission’s alignment with the Secretary) is well illustrated by a \nnumber of landmark orders approving several market new constructs that we issued since \nOctober, which together operationalize the Secretary’s principles and laid groundwork \nfor meaningful reform and today’s actions.7  While working to develop those orders, the \n \n3 Secretary’s Letter at 2. \n4 Id. \n5 See SEC v. Chenery Corp., 332 U.S. 194, 202-03 (1947) (“[A]n administrative \nagency must be equipped to act either by general rule or individual order.  To insist upon \none form of action to the exclusion of the other is to exalt form over necessity. . . . [T]he \nchoice made between proceeding by general rule or by individual, ad hoc litigation is one \nthat lies primarily in the informed discretion of the administrative agency.”); Wis. Gas \nCo. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985) (“It is a well-settled principle of \nadministrative law that the decision whether to proceed by rulemaking or adjudication \nlies within the broad discretion of the agency.”). \n6 “[T]he Commission may rely on ‘generic’ or ‘general’ findings of a systemic \nproblem to support imposition of an industry-wide solution.”  Interstate Nat. Gas Ass’n \nof Am. v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002) (internal citations omitted).  However, \nthe Commission “has long allowed different regional transmission organizations to \nfollow different rules, in recognition of regional variations including potential differences \nin ‘geographic size and location.’”  Cent. Hudson Gas & Elec. Corp. v. FERC, 138 F.4th \n531, 539 (D.C. Cir. 2025) (internal citations omitted). \n7 See id. P 2 & nn.6-11."},{"page":86,"startToken":32442,"endToken":32879,"text":"Docket No. EL26-67-000  \n \n- 4 - \n \n \nCommission has simultaneously devoted significant attention to evaluating the various \nprocedural paths through which we might comprehensively deliver. \n \nIndividual show cause proceedings will allow the Commission to ensure that \nsolutions to the problems the Secretary identified are tailored to the specific, varied \ncircumstances and market constructs of each region.  Indeed, a careful review of today’s \nsix orders reveals the many ways in which those orders are customized for each market’s \nunique circumstances and progress (or lack thereof) towards serving large load.  To name \njust a few examples, the orders recognize ongoing stakeholder processes in various \nregions and are adapted to existing tariff provisions concerning large and co-located \nloads; account for regional variances in allocating rights and responsibilities among \nRTOs/ISOs and the transmission owners; leave room for each market to tailor operational \nrequirements for large loads that are particular to their region; and otherwise account for \nincumbent regional differences on topics such as cost allocation and cost transparency, \nstudy processes, and network upgrade procedures. \n \nProceeding via show cause proceedings will also allow the markets (and their \nrespective transmission owners) to explain, in the first instance, how to address the \nCommission’s concerns.  These entities have the deepest understanding of their \nrespective regions and are best positioned to implement solutions we identified, in the \nmost expeditious manner.  The Commission will promptly evaluate their responses to \ntoday’s orders, and, with input from stakeholders, swiftly establish appropriate reforms.   \n \nSecond, proceeding via individual show cause orders will allow the Commission \nto act more quickly than through traditional rulemaking.  Notice-and-comment \nrulemaking may not capitalize upon individual market progress prompted since October \nand would be unduly time-consuming,8 as it also inevitably would require the additional \nsteps of accommodating the regional variations of the approach we take today.  \nRulemaking efforts can be particularly inefficient when, as here, they risk incubating \nuncertainty after progress has begun, and diverting scarce stakeholder resources away \nfrom other endeavors, such as the development of market-specific reforms submitted to \nthe Commission under section 205 of the Federal Power Act (FPA).  (To be clear, we \nvery much encourage 205 submissions encapsulating the principles we articulate in the \n206s, and with all due deliberate haste.) \n \nFurthermore, rulemaking requires a lengthy series of steps before the proposed \nreforms would actually take effect—e.g., a NOPR, then a final rule, then potential orders \non rehearing, and then a “compliance” process in which affected parties make filings (or, \nmore likely, multiple rounds of filings) explaining how they intend to implement the rule. \n \n8 See, e.g., Comments of Talen Energy Corporation, Docket No. RM26-4, at 5-6 \n(filed Nov. 21, 2025)."},{"page":87,"startToken":32879,"endToken":33357,"text":"Docket No. EL26-67-000  \n \n- 5 - \n \n \nBy their nature, these procedures take time.  For example, the compliance process for the \nCommission’s Order No. 20239 (which matured out of an ANOPR issued in July 2021 \nand a NOPR issued in June 2022) still is not fully complete as of June 2026.  The \ncompliance process for Order No. 222210 (NOPR issued in November 2016) could be \nconsidered completed in May 2026; however, even with that timing, not all of the \nRTOs/ISOs have yet fully implemented their Commission-accepted market rules.  I \nprovide these examples not to suggest that the completion of a rulemaking process on the \ninterconnection of large loads would take this long,11 but rather to make clear the scope \nof the years-long delays in implementation that might be expected if the Commission \nelected to proceed via a NOPR.  By contrast, we expect that individual show cause \nproceedings for each of the RTO/ISOs will enable the Commission to spearhead lasting \nreform much more expeditiously.   \n \nThe six markets together cover nearly two-thirds of load subject to Commission-\njurisdictional rates, and therefore focusing initially on those regions is a prudent first step.  \nBut I am under no illusion that the challenges discussed in today’s orders are somehow \nunique to the RTO/ISO regions.  Our actions today do not foreclose the possibility of a \nfuture rulemaking, and nor do they prevent us from acting on filings made under sections \n205 and 206 of the FPA.  I encourage transmission providers and other stakeholders \noutside RTO/ISO regions to make individual filings to address the issues we discuss \ntoday. \n \nFERC is no longer the sleepy, responsive agency of the past—our country cannot \nafford for it to be.  This is a time for the best thinkers we have to collaborate on solving \nour biggest problems, and thus it is my great honor to deliver a solution that honors the \nSecretary’s goals.   \n \n9 Improvements to Generator Interconnection Procs. & Agreements, Order No. \n2023, 184 FERC ¶ 61,054, order on reh’g, 185 FERC ¶ 61,063 (2023), order on reh’g, \nOrder No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ 61,134 (2024). \n10 Participation of Distributed Energy Res. Aggregations in Mkts. Operated by \nReg’l Transmission Orgs. & Indep. Sys. Operators, Order No. 2222, 172 FERC ¶ 61,247 \n(2020), order on reh’g, Order No. 2222-A, 174 FERC ¶ 61,197, order on reh’g, Order \nNo. 2222-B, 175 FERC ¶ 61,227 (2021). \n11 I do not mean to suggest that the public utilities subject to compliance under \nthese rulemakings—or the Commission itself—have been derelict.  The time-consuming \nnature of the compliance process is a natural consequence of complex, nuanced efforts \ntoward tariff reform.  As Chairman, I will continue to evaluate Commission directives to \nensure that obligations on regulated entities are not unduly burdensome and to make \ncertain that Commission action during the compliance process is as timely as possible."},{"page":88,"startToken":33357,"endToken":33371,"text":"Docket No. EL26-67-000  \n \n- 6 - \n \n \nFor these reasons, I respectfully concur.   \n______________________ \nLaura V. Swett \nChairman"},{"page":89,"startToken":33371,"endToken":33547,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C.  \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. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAppalachian Power Company \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nDayton Power and Light Company \nDelmarva Power & Light Company \nDuke Energy Kentucky, Inc. \nDuke Energy Ohio, Inc. \nDuquesne Light Company \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nIndiana Michigan Power Company \nJersey Central Power & Light Company \nKentucky Power Company \nKeystone Appalachian Transmission Company \nKingsport Power Company \nLinden VFT, LLC \nMid-Atlantic Interstate Transmission, LLC \nMonongahela Power Company \nNeptune Regional Transmission System, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nOhio Power Company \nOhio Valley Electric Corporation \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nThe Potomac Edison Company \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nDocket No. EL26-67-000"},{"page":90,"startToken":33547,"endToken":33921,"text":"Docket No. EL26-67-000  \n- 2 - \n \n \nSilver Run Electric, LLC \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nVirginia Electric and Power Company \nWabash Valley Power Association, Inc. \nWheeling Power Company \n \n(Issued June 18, 2026) \n \nROSNER, Commissioner, concurring:  \n \n \nThe electric industry is in the midst of changes not seen in a generation.  \nCompared to more traditional load growth, the large loads seeking to connect to the grid \ntoday are larger, sometimes by orders of magnitude, and more concentrated.  They also \nexhibit different operational characteristics, such as the ability to quickly change their \nenergy consumption, sometimes in seconds.  Often, these large loads seek to connect to \nthe grid as quickly as possible.  And because of these dynamics, large loads are rapidly \ndriving the need for new transmission infrastructure and energy supply.  This creates new \nchallenges that, if unaddressed, could jeopardize the reliability and affordability of the \ngrid on which we all depend. \n \nToday, we are taking an important step toward addressing these challenges.  We \nare opening a dialogue with each of the six RTO/ISOs on a series of reforms that are \ntailored to address the unique reliability and affordability challenges posed by large load \ngrowth and the infrastructure buildout needed to serve dramatically growing demand.  \nInformed by the record developed in response to the Secretary of Energy’s October 2025 \nANOPR,1 and by innovative proposals that stakeholders have filed with the Commission \nunder FPA section 205, today’s orders are aimed at ensuring that the grid remains reliable \nand affordable for all customers, especially residential customers.  It is also crucial that \nwe unlock the immense economic opportunity that once-in-a-generation growth \nrepresents.  While each order’s specific focus varies according to the progress that each \nRTO/ISO has made, our actions today fit broadly into four key pillars that, taken \ntogether, provide a foundation for durable reform.  Today, we are: (1) Protecting \nConsumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering \nInnovation (see Figure 1).  I write separately to explain how. \n \n1 U.S. Dep’t of Energy, Secretary of Energy Chris Wright, Direction that the \nCommission Initiate Rulemaking Procedures and Proposal Regarding the Interconnection \nof Large Loads Pursuant to the Secretary’s Authority Under Section 403 of the \nDepartment of Energy Organization Act (Oct. 23, 2025)."},{"page":91,"startToken":33921,"endToken":34382,"text":"Docket No. EL26-67-000  \n- 3 - \n \n \n***** \n \nProtecting Consumers:  Today’s orders include key protections that promote \naffordability.  First, today’s orders require “Cost Recovery Agreements”, which are \ndesigned to ensure that large loads pay their fair share of the costs incurred to serve them, \nregardless of whether the large load comes online as planned.  Thus, if new infrastructure \nis built to accommodate a data center, and that data center doesn’t show up, residential \ncustomers are not left on the hook to pay the costs.  Cost Recovery Agreements prevent \nthose costs from being shifted to residential customers.  Depending on how they are \nstructured, Cost Recovery Agreements can also address the potentially uneven pacing of \nnew infrastructure costs, where grid upgrade costs may hit customer bills before the large \nload is fully online and energized.  Data centers have committed to paying their own \nway.2  Today, with “Cost Recovery Agreements,” we are taking steps to ensure that those \ncommitments are honored.  I note, however, that the door remains open to other creative, \nregionally-specific ideas to protect consumers.  If there are other ways to accomplish that \ngoal, I welcome those proposals. \n \nAnother win for consumers is requiring RTO/ISOs to consider grid enhancing \ntechnologies (GETs), including dynamic line ratings, when adding new large loads to the \ngrid.  GETs are technologies that squeeze more juice out of the existing grid, reducing the \nneed for expensive upgrades and speeding up the time connect.  Ensuring that RTO/ISOs \nconsider GETs in the planning process—and if GETs are not used, explain why—not \nonly helps new large loads get connected more quickly, but is also a commonsense step \ntowards saving all consumers money.  Put differently, today’s orders will help us \nunderstand if we are leaving efficiencies on the table, an outcome we cannot afford. \n \nSafeguarding Reliability:  Today’s orders safeguard reliability.  They help ensure \nthat RTO/ISOs use study procedures and operational requirements that reflect large \nloads’ unique characteristics and the reliability impacts of connecting them to the grid.  \nThose novel characteristics and reliability impacts are well-documented, and it is not \nclear if existing study procedures or operational requirements account for them.  Clear, \ncomprehensive, and specifically tailored study procedures and operational requirements \nare needed, such as enhanced data reporting and telemetry to increase visibility into how \nthese loads interact with the grid, and today’s orders represent progress towards this goal. \n \nFinally, although not part of today’s orders, I want to highlight NERC’s ongoing \nefforts to establish registration criteria for large computational loads and to develop \nreliability standards.3  NERC’s goal is to finish the first phase of this critical work this \n \n2 See Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026). \n3 NERC, Large Loads Action Plan Q1 2026 Update (Apr. 2026), \nhttps://www.nerc.com/globalassets/initiatives/large-loads-action-plan/llap-quarterly-"},{"page":92,"startToken":34382,"endToken":34758,"text":"Docket No. EL26-67-000  \n- 4 - \n \n \nyear.  It is essential that NERC meet this deadline.  I encourage all stakeholders to \nparticipate in NERC’s process. \n \nEnhancing Transparency:  Today’s orders provide regulators—the Commission \nand, critically, our state partners—and customers with data on how connecting large \nloads to the grid affects bills.  Today’s orders embody a commonsense approach: if a  \nNetwork Upgrade is built to connect a large load to the grid, consumers should know who \nthat upgrade was built for and what it cost. \n \nTransparency is important because “who pays?” has been and continues to be a \nfraught and contentious question for large load interconnection.  Stakeholders, including \nstate regulators and the ratepayers that they represent, must know the costs, for whom \nthey are being incurred, and how they are being allocated, to know that everyone is \npaying their fair share.  Today’s orders ensure that this information is public, accessible, \nand clear.  State regulators in more than half of the country have enacted large load \ntariffs.4  Our action today helps them as they continue their critically important work. \n \nThe Commission’s action today also addresses speculative load interconnection \nrequests, which clog up load interconnection queues, divert resources, and distort \nforecasts.  Under current rules, data centers can (and are incentivized to) “shop around” \ntheir prospective projects with different utilities to identify the fastest and cheapest \nlocation to connect.  This wastes time and resources studying projects that are not real.  \nWorse yet, it can inflate expected load growth by modeling projects that do not \nmaterialize, leading to double counting, inaccurate market signals, and unnecessarily high \nprices for consumers.  Today, we target speculative projects by establishing escalating \nreadiness requirements for distinct phases of the study process to deter duplicative or \nspeculative requests for transmission service.  I strongly encourage RTO/ISOs to pursue \nother improvements to load forecasts, such as using objective screening criteria like \nphysical site control, to ensure that the data used to plan the grid is as accurate as \npossible.5   \n \nupdate-q1-2026.pdf. \n4 See, e.g., National Association of Regulatory Utility Commissioners \nSupplemental Comments at 2-6; Edison Electric Institute Supplemental Comments at \nApp. 9-13. \n5 See Comm’r David Rosner, Letter to the RTOs/ISOs on Large Load Forecasting \n(Sept. 18, 2025), https://www.ferc.gov/news-events/news/chairman-rosners-letter-\nrtosisos-large-load-forecasting."},{"page":93,"startToken":34758,"endToken":35224,"text":"Docket No. EL26-67-000  \n- 5 - \n \n \n \nFostering Innovation:  As I have said, to meet the moment, “a business-as-usual \napproach . . . will not suffice.”6  Building new infrastructure is difficult and costly, which \ndelays efforts to connect large loads to the grid quickly, reliably, and cost effectively.  \nThis is doubly true when generation and load are planned and studied separately.  \nToday’s orders push beyond this status quo. \n \nFirst, today’s orders promote flexible transmission services—that is, non-firm \nservice to a co-located load that is willing and able to limit withdrawals from the grid—in \nevery RTO/ISO (see Figure 2).  As we explained when we first created these \ntransmission services in PJM for co-located loads, customers willing to embrace \nflexibility can reduce the need for Network Upgrades and generating capacity to serve a \nco-located load, which speeds up connecting to the grid and reduces costs for the co-\nlocated load as well as other retail customers. \n \nSecond, today’s orders recognize that extending these same transmission services \nto large loads that are not co-located but that may also be willing to limit their \nwithdrawals from the grid can unlock even more efficiency.  Just as for co-located loads, \nlegalizing flexible transmission service options for more large load customers can speed \ninterconnection, avoid constructing unnecessary transmission upgrades, reduce strain on \nthe grid, and make power bills cheaper for everyone. \n \nFinally, today’s orders embrace yet another innovation.  Load and generation need \nnot be co-located to reduce the number of Network Upgrades; in other words, literal co-\nlocation is not the only way to facilitate faster, more efficient, and more cost-effective \nconnections to the grid.  Rather, where a large load and an associated generator are \nelectrically proximate (i.e., close together) and studied together, the reliability impacts on \nthe grid may be more limited than if the load and generator are studied separately.  Just \nlike with co-location, more limited impacts on the grid mean, all else equal, fewer \nNetwork Upgrades, which makes connecting to the grid faster, more efficient, and \ncheaper for both the large load and the associated generator.  That last point is key.  To \nadd new supply to the grid, we must create incentives for “Bring Your Own New \nGeneration.”  Today’s orders make BYONG faster and more efficient.  \n \nSPP has been a leader in showing how to push beyond the status quo.  With its \ninnovative HILLGA proposal, approved by the Commission in January,7 SPP leveraged \nthe opportunity for speed and efficiency by studying load and generation together, and by \ncreating a limited, expedited interconnection service to connect faster.  By matching the \ngenerator’s output to the electrically proximate large load’s demand, the impacts to the \n \n6 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2026), (Rosner, Comm’r, \nconcurring) at P 3. \n7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026)."},{"page":94,"startToken":35224,"endToken":35592,"text":"Docket No. EL26-67-000  \n- 6 - \n \n \ngrid are less than they otherwise would be, minimizing the need for time-consuming and \ncostly Network Upgrades needed to connect.  HILLGA is one solution that works for \nSPP, but today’s orders direct other regions to follow SPP’s lead in ways that work for \nthem.  Today’s orders add a key tool by ensuring that all RTO/ISOs can study load and \ngeneration together.  \n***** \n \nThe Commission’s action today is an important step forward, but the Commission \ncannot accomplish this work alone.  States are essential partners in this work.  The \nCommission’s actions here respect the long-standing jurisdictional line between federal \nand state authority provided by Congress and repeatedly affirmed by the Supreme Court.  \nStates retain exclusive jurisdiction to allocate the costs of FERC-jurisdictional \ntransmission charges among their retail ratepayers, including co-located loads.  States \nalso hold the keys to energy infrastructure permits, so we rely on their decisions to ensure \nthat needed transmission and generation get built.  At a time when some large loads are \nretail customers that can consume as much energy as a small city, it is imperative that we \nwork within our respective jurisdictions, but that we collaborate. I look forward to \ncontinued collaboration. \n \nToday’s orders begin an important dialogue with RTO/ISOs.  As a potential next \nstep, today’s orders invite RTO/ISOs to respond by submitting proposals under FPA \nsection 205.  I cannot encourage this enough.  I also encourage public utilities outside of \nRTO/ISOs across the country to do the same.  The electric industry is rapidly evolving \nwith regions experiencing and addressing these challenges in different ways.  Many of \nthe examples on which the actions in today’s orders are based on stakeholders thinking \ncreatively to develop solutions, and I welcome other new, innovative, and regionally \ntailored proposals that build on the four key pillars set forth today:  (1) Protecting \nConsumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering \nInnovation.  Only by working together can we rise to the occasion and meet this once-in-\na-generation moment to deliver the reliable and affordable energy on which we all \ndepend.  It will not be easy, but I remain optimistic and look forward to the path ahead. \nFor these reasons, I respectfully concur. \n \n \n \n________________________ \nDavid Rosner \nCommissioner"},{"page":95,"startToken":35592,"endToken":35594,"text":"Figure 1"},{"page":96,"startToken":35594,"endToken":35596,"text":"Figure 2"},{"page":97,"startToken":35596,"endToken":35772,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C.  \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. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAppalachian Power Company \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nDayton Power and Light Company \nDelmarva Power & Light Company \nDuke Energy Kentucky, Inc. \nDuke Energy Ohio, Inc. \nDuquesne Light Company \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nIndiana Michigan Power Company \nJersey Central Power & Light Company \nKentucky Power Company \nKeystone Appalachian Transmission Company \nKingsport Power Company \nLinden VFT, LLC \nMid-Atlantic Interstate Transmission, LLC \nMonongahela Power Company \nNeptune Regional Transmission System, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nOhio Power Company \nOhio Valley Electric Corporation \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nThe Potomac Edison Company \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nDocket No. EL26-67-000"},{"page":98,"startToken":35772,"endToken":36164,"text":"Docket No. EL26-67-000 \n- 2 - \n \n \nSilver Run Electric, LLC \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nVirginia Electric and Power Company \nWabash Valley Power Association, Inc. \nWheeling Power Company \n \n(Issued June 18, 2026) \n \nSEE, Commissioner, concurring:  \n \n \nGrowing electricity demand underscores America’s economic strength and the \nopportunities that come with it.  And with new opportunities come new challenges.  The \npace and scale of emerging large loads create new circumstances that require us to adapt \nin how we build and manage the grid.  Large and flexible loads can materially change \nsystem operations, for instance, as well as near-term planning needs, upgrade \nrequirements, and how we allocate costs.  Most existing systems were not designed to \naccommodate those changes—especially not at the pace needed to support AI growth and \nadvanced manufacturing that are central to America’s economic competitiveness.  As a \nresult, uncertainty over the operative rules and delays in interconnecting large loads can \nundermine reliability and investment and add unacceptable and avoidable costs.  \n \nToday, the Commission takes strong action within our jurisdictional sweep to \naddress these and other challenges that large load growth poses to the interstate \ntransmission system.  Today’s orders support both just and reasonable rates and speed to \n(reliable) power.  I’m deeply grateful for the many commenters who shared their insight \nand ideas in this action.  They let us build a record that highlights the need for clearer \nprocesses, better information, and faster analysis while our country moves new large load \nadditions online.  As we press forward in these dockets, I will be looking to continue \nbuilding on the momentum already underway across the country to craft more practical, \nregion-specific solutions that support timely action while protecting consumers.  Our \ncontinued ability to deliver reliable and affordable electricity requires nothing less.   \n \nToday’s orders speak for themselves.  I write separately to briefly highlight two \nprinciples baked throughout them and that I believe must remain central as the \nCommission evaluates further steps.   \n \nFirst, these issues extend beyond the Commission.  Creating efficient, predictable \nlarge load interconnection processes is a joint and overlapping task for us, other federal \nagencies, the States, and the RTOs/ISOs and utilities.  My animating principle here is that \nwe must use FERC’s statutory authority to bring clarity to the parts of this national issue \nwe own, and to complement and aid others as they tackle theirs.  The very procedure the"},{"page":99,"startToken":36164,"endToken":36595,"text":"Docket No. EL26-67-000 \n- 3 - \n \n \nCommission deploys today reflects that goal: Recognizing the value in region-specific \napproaches, we are directing individual action in each of the RTO/ISO regions and \nencouraging—strongly—proposals under section 205 of the Federal Power Act from \ntransmission providers or other entities that are molded to their unique system needs. \n \nMost critically, exercising our authority fully without hamstringing our regulatory \nand industry partners means respecting the States.  States make many of the key decisions \nthat affect how we manage large loads.  States bring indispensable expertise over local \nconditions, siting needs, retail structures, and the resource decisions within their borders.  \nAnd they have been hard at work pursuing the retail implications and other State-specific \nconcerns that large load interconnection presents.1  All this effort flows from the States’ \nstatutorily preserved role in regulating the power system.  Today’s order understands that \nlimit—our power “extend[s] only to those matters which are not subject to regulation by \nthe States.”2  It also embraces the value in a statutory lens that views large load issues as \nan area of shared federal-State responsibility.  As we require clear study and operational \nparameters for large load interconnection, we should remember that the nation’s energy \nlandscape is not monolithic.  State and regional diversity is a strength, and today’s orders \nknow that the best solutions reflect differing system characteristics.  Our action today is \ndesigned to support further State efforts in this urgent and fast-moving space, not \noverride them. \n \nSecond, affordability must be at the forefront as we protect consumers from \nunnecessary costs in a time of rising demand.  True, the Commission lacks authority over \nall the factors that drive electricity costs at the retail level.  Today’s orders recognize that.  \nIn response, the orders strive to aid the States in their front-line affordability duties by \ngetting into their hands all relevant information about Commission-jurisdictional costs.  \nAs these matters move forward, I am particularly interested in continued feedback from \nthe States on what information they most need to assess cost implications as new loads \ncome online.  Are the cost transparency measures we identify today sufficient, or are \nadditional or more granular data needed for States to appropriately suballocate \ntransmission costs among retail customers?  Tools like alternative cost allocation \nstructures, greater clarity in transmission service agreements, accounting for States’ \nlarge-load-specific tariffs, and direct assignment in appropriate cases may help States \nensure that retail consumers do not bear costs incommensurate with the benefits they \nreceive. \n \n1 See EEI Supplemental Comments at Appendix 9 – 13 (listing pending and \napproved State large load tariffs).  \n2 16 U.S.C. § 824(a)."},{"page":100,"startToken":36595,"endToken":37102,"text":"Docket No. EL26-67-000 \n- 4 - \n \n \n \nMoving to areas where the Commission has a more direct role in ensuring cost \nresponsibility, we need to pull all the levers we have to keep rates fair and transparent.  \nToday we reaffirm our responsibility to assign jurisdictional costs to the customers who \ndrive or benefit from grid upgrades, not shift them onto families and small businesses.  \nFor instance, today’s orders seek to reduce large-load driven network upgrade costs \nthrough alternative transmission technologies, or ATTs (also commonly called Grid \nEnhancing Technologies).  In determining how best to meet the needs of this historic \nlarge load growth, technologies that can improve system capability faster than traditional \nupgrades and at lower costs deserve a hard look.  ATTs may not be the best tool in every \ncircumstance, but where they are they can support timely interconnections and avoid \npotentially tens or hundreds of millions of dollars in unnecessary network upgrade costs \nthat would otherwise flow into transmission customers’ bills.    \n \nSo our approach today supports continuing the Commission’s policy to roll most \nnetwork upgrade costs—including those in the large load space—into the embedded-cost \nrate most transmission customers pay.  But it includes an asterisk that this policy works \nfor ratepayers only so long as we remain committed to pursuing technological \ninnovations that keep those costs at a responsible and accountable level.  Today’s order \nthus calls for transmission providers to sufficiently evaluate ATTs to assess if and how \nthey can meet large loads’ interconnection needs.  The answer may be yes or no in a \ngiven case.  But if the transmission provider opts for traditional network upgrades, they \nmust demonstrate why ATTs are not feasible or would not result in lower costs or a faster \ntimeline for the large load interconnection customer.  In short, the goal is to respect \ntransmission providers’ engineering judgments while protecting against upgrade costs \nwhen ATTs could solve transmission needs faster and with a lower bill.    \n \nI am also sensitive to novel questions about cost shifting that interconnecting large \nload may present.  Today’s findings on cost recovery agreements between transmission \nowners and Eligible Customers are an important step in mitigating the risks of stranded \nassets if large loads prove speculative.  We are also reducing unnecessary redundancy by \nallowing an Eligible Customer to meet its financial security requirements by relying on \ncredit support or other financial security a large load customer may have posted under a \nretail agreement.  As we gain more experience studying transmission service requests on \nbehalf of large loads, it may become appropriate to further streamline financial security \narrangements.  Perhaps, for instance, cost -recovery agreements between a transmission \nowner and a large load customer itself could satisfy an Eligible Customer’s financial \nsecurity requirements.  As we move forward, I’ll be looking to ensure cost-recovery \nagreements contain fair and transparent measures to ensure the right costs get on the right \nbills.  (Relatedly, the discussion about the full nature of transmission-related charges in \nour concurrent PJM Order on Rehearing, Clarification, Compliance, and Paper Hearing 3 \n \n3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026)."},{"page":101,"startToken":37102,"endToken":37293,"text":"Docket No. EL26-67-000 \n- 5 - \n \n \nmay prove relevant here: Real-world experience with new transmission services for co-\nlocated load may clarify if future action becomes needed to address potential cost shifts \nas Eligible Customers take new transmission services on behalf of large loads.4)   \n \nMore generally, as we gain more experience as an industry and a country in \ngetting large loads connected to the grid, I welcome bold proposals to keep affordability \ncentral.  Large load growth presents a real opportunity to build a stronger, more capable, \nand more reliable electric system that can benefit all ratepayers.  Meeting that opportunity \nat the pace we need and at an acceptable cost requires innovative thinking and fast action.  \nI commend the States in their continued work in these areas.  I urge the RTOs and ISOs \nto continue their good work as they respond quickly to today’s orders.  I also remain \ncommitted to moving forward within the Commission’s statutory zone with clarity and \ndecisiveness.  I am proud to support the Commission’s important steps today.  And we all \nhave more work ahead.    \nFor these reasons, I respectfully concur.  \n \n \n \n______________________________ \nLindsay S. See \nCommissioner \n \n4 See id. P 456."},{"page":102,"startToken":37293,"endToken":37469,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C.  \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. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAppalachian Power Company \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nDayton Power and Light Company \nDelmarva Power & Light Company \nDuke Energy Kentucky, Inc. \nDuke Energy Ohio, Inc. \nDuquesne Light Company \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nIndiana Michigan Power Company \nJersey Central Power & Light Company \nKentucky Power Company \nKeystone Appalachian Transmission Company \nKingsport Power Company \nLinden VFT, LLC \nMid-Atlantic Interstate Transmission, LLC \nMonongahela Power Company \nNeptune Regional Transmission System, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nOhio Power Company \nOhio Valley Electric Corporation \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nThe Potomac Edison Company \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nDocket Nos. EL26-67-000"},{"page":103,"startToken":37469,"endToken":37805,"text":"Docket No. EL26-67-000 \n- 2 - \n \n \nSilver Run Electric, LLC \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nVirginia Electric and Power Company \nWabash Valley Power Association, Inc. \nWheeling Power Company \n \n(Issued June 18, 2026) \n \nCHANG, Commissioner, concurring: \n \n \nIn a series of orders today, the Commission initiates separate proceedings under \nFederal Power Act (FPA) section 206 to explore the impact of the increasing growth of \nlarge loads in Regional Transmission Organization (RTO) and Independent System \nOperator (ISO) regions.  The preliminary findings in these orders, and the associated \nproposed reforms to RTO/ISO and transmission owner tariffs, could significantly change \nhow loads procure, use, and pay for transmission service, with ramifications for \nRTO/ISO operations, planning, and markets.  I write separately to emphasize the \nimportance of building actionable records in these proceedings, particularly with respect \nto our consideration of customer protection, transmission service, and alternative \ntransmission technology reforms. \nI. \nOverview of Today’s Orders \n \nIn each of today’s orders to show cause, the Commission identifies a series of \nissues raised by the ongoing growth of large loads, directs briefing on whether existing \ntariffs remain just and reasonable in light of those developments, and describes possible \nsolutions to those issues if the Commission ultimately concludes that the relevant tariffs \nare unjust and unreasonable.  Each order is directed to a specific RTO/ISO and relevant \ntransmission owners that play a role in interconnecting large loads to the Commission-\njurisdictional transmission system.  The Commission does not pursue the broad assertion \nof jurisdictional authority contemplated in the Advanced Notice of Proposed \nRulemaking, which I hope assuages concerns raised by our state colleagues that the \nCommission ought not encroach upon matters properly left to their jurisdiction.1   \n \n1 I will do my part to ensure that the Commission continues to be a collaborative \npartner to our state counterparts, other federal agencies, and the industry as we seek to \naddress this wide-ranging challenge.  Accordingly, I welcome feedback from our state \ncolleagues and others if they believe the Commission’s preliminary findings raise \njurisdictional concerns."},{"page":104,"startToken":37805,"endToken":38264,"text":"Docket No. EL26-67-000 \n- 3 - \n \n \n \nBroadly summarized, each order seeks regional input on a specific list of issues: \n(1) the clarity and consistency of existing rules governing how each RTO/ISO and its \nrelevant transmission owners analyze the impact of providing transmission service to \nEligible Customers on behalf of large loads; (2) whether each RTO/ISO tariff requires \nreforms to mitigate the risk of cost shifting among wholesale transmission customers; (3) \nwhether each RTO/ISO tariff (other than PJM) requires additional clarity regarding the \nprovisions addressing co-located generation and load arrangements; (4) the potential \nextension of new firm and non-firm transmission services to co-located load, load with \nbehind the meter generation, and other flexible loads; and (5) the need for reforms, \nmodeled on Southwest Power Pool, Inc.’s High Impact Large Load Generation \nAssessment concept, to facilitate a process through which a generator may temporarily \nserve a co-located or electrically proximate load until interconnection and transmission \nservice is available.  The Commission also invites each region to submit FPA section 205 \nfilings that can address each issue identified in the orders, thereby resolving the \nCommission’s concerns.   \nII. \nThe Commission Needs Good Records to Ensure Reasoned Decision-Making   \n \nI first want to emphasize that the Commission needs active participation from \ninterested stakeholders to develop thorough records in each region.  The Commission \ncannot make reasoned decisions about whether reforms might be needed without an \naccurate understanding of the existing processes, which differ by region.  Because the \nCommission is acting via FPA section 206 rather than generically through a rulemaking, \nthe issues addressed by these orders will be subject to ex parte restrictions across the \nRTOs/ISO regions, including with our state colleagues whose regulation can and will \ndirectly affect the individual transmission owners that need to comply with the orders \nissued today.  This will limit the Commission’s ability to engage in informal fact-finding \nand discussions with regional stakeholders, and thus, it is even more essential that the \nrecord in each region fully reflects the views of all interested parties.   \n \nSecond, I highlight three issues below that will be especially important to the \nsuccess of this effort, and I hope that interested parties will take particular care in helping \nthe Commission address those issues.  Importantly, I recognize that the record established \nin each RTO/ISO region will (and should) differ, which will allow the Commission to \nensure any required changes to an RTO/ISO’s tariff are appropriately tailored to that \nregion’s needs. \nIII. \nThe Commission Needs to Pursue Meaningful Customer Protection  \n \nThe FPA is fundamentally a customer protection statute,2 and the Commission has \nan obligation to ensure that the rates that wholesale and transmission customers pay are \n \n2 See, e.g., Mun. Light Bds. Of Reading and Wakefield v. FPC, 450 F.2d 1341,"},{"page":105,"startToken":38264,"endToken":38706,"text":"Docket No. EL26-67-000 \n- 4 - \n \n \njust and reasonable.  Rapid large load growth has strained planning and resource \nprocurement processes around the country, as transmission owners, load serving entities, \nand generators accelerate the building of new infrastructure needed to serve these new \nloads.  As we develop the new infrastructure, many have raised concerns about whether \nthese costs are being fairly assigned to new and existing customers, whose benefits must \nbe commensurate with the costs they pay.  While individual states have been exploring or \nusing various approaches to protect retail customers against unjustified cost shifts, the \nCommission to date has not initiated any proactive exploration of how to protect \nwholesale customers against unjustified cost shifts. I am laser-focused on this issue \nbecause we should not create unjustified costs for consumers in our efforts to connect and \nserve large loads.  \n \nIn today’s orders, the Commission launches an inquiry into whether existing \nRTO/ISO tariffs include adequate mechanisms to mitigate the risk of undue cost shifting \namong transmission customers.  To address this risk, the Commission preliminarily \nidentifies a two-part solution: (1) that each RTO/ISO post public information about the \namount of new large loads seeking to connect to the RTO’s/ISO’s transmission system, \nany Network Upgrades identified in the local transmission planning process to serve \nthose loads, and the costs of those Network Upgrades; and (2) that each RTO/ISO adopt a \npro forma cost recovery agreement to help ensure that Eligible Customers serving large \nloads bear the risk and are ultimately responsible for costs incurred to provide \ntransmission service.  I strongly support this effort to provide additional transparency \nregarding jurisdictional transmission service requests and the costs associated with \nproviding transmission service to the requesting parties, as the Commission cannot \neffectively execute its statutory responsibilities without sufficient understanding of the \ncosts that feed into jurisdictional rates.   \n \nExploring how agreements between transmission owners and Eligible Customers \ncan protect wholesale customers against cost shifts is important.  However, as I have \npreviously explained, bilateral agreements that simply provide transmission revenue \ncontributions untethered from any assessment of the actual cost of providing transmission \nservice induced by individual large loads may be insufficient to adequately protect other \ncustomers against unjustified cost shifts.3  It is therefore important that the resulting \nregulatory and rate design are not limited to a pre-defined solution set, and that parties \nprovide the Commission with comprehensive records outlining various and innovative \n \n1348 (D.C. Cir. 1971) (stating that the FPA’s “primary aim is the protection of \nconsumers from excessive rates and charges”). \n3 E.g., PECO Energy Co., 193 FERC ¶ 61,148 (2025) (Comm’r \nChang, concurring); Commonwealth Edison Co., 194 FERC ¶ 61,109 (2026) (Comm’r \nChang, concurring)."},{"page":106,"startToken":38706,"endToken":39109,"text":"Docket No. EL26-67-000 \n- 5 - \n \n \napproaches to protect customers.  I am encouraged by the continued development of the \nANOPR record on this subject,4 innovative solutions being developed at the state level,5 \nand a growing body of thoughtful analyses and proposed approaches to provide customer \nprotection for costs driven by large load growth.6  Without prejudging any particular \nproposed solution, the Commission needs a robust record in each docket and each region \nto ensure we establish the right cost shift protections for wholesale customers, including \nbut not limited to the commitments outlined in the Ratepayer Protection Pledge.7   \n \nI support initiating our own review of customer protection approaches, rather than \nsimply relying on voluntary commitments that may fall short of optimal protection, \nbecause the Commission has the opportunity and obligation to get this issue right.  I \ntherefore encourage interested parties to assist the Commission in that effort by clearly \nand comprehensively explaining the benefits and tradeoffs of alternative customer \nprotection approaches.  How power infrastructure costs will be assigned across Eligible \nCustomers that serve large loads and other customers is at the core of the efforts we \ninitiate today.       \nIV. \nThe Commission Needs to Understand the Implications of Extending New \nTransmission Services to Additional Loads and Regions \n \nThe orders also preliminarily find that the Commission should extend the \ntransmission services developed in the PJM co-location proceeding – Interim NITS, Firm \nContract Demand, and Non-Firm Contract Demand – to new types of load and new \n \n4 E.g., Interconnection of Large Loads to the Interstate Trans. Sys., Supplemental \nComments of FirstEnergy Svc. Co., Docket No. RM26-4-000 (filed June 5, 2026); id., \nComment of the Harvard Electricity Law Initiative, Docket No. RM26-4-000 (Apr. 15, \n2026); id., Supplemental Comments of WIRES, Docket No. RM26-4-000 (Mar. 30, \n2026). \n5 E.g., Utility Dive, Microsoft seeks Nevada tariff to shield ratepayers from data \ncenter costs (June 8, 2026), available at https://www.utilitydive.com/news/microsoft-\nseeks-nevada-tariff-to-shield-ratepayers-from-data-center-costs/822250/. \n6 E.g., Travis Kavulla, How Will Data Centers Pay for Power?, American Affairs \n(may 2026), available at https://americanaffairsjournal.org/2026/05/how-will-data-\ncenters-pay-for-power/ ; Electricity Customer Alliance, A Customer-Centric Agenda for \nthe Federal Energy Reg. Comm’n (Jan. 2026), available at https://lnkd.in/em-apfuQ; \nGrid Strategies, Federal Transmission Pricing Vol. 2, Options for Ensuring Affordability \nin an Era of High Load Growth (June 2026), available at \nhttps://gridstrategiesllc.com/project/federal-transmission-pricing.  \n7 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":107,"startToken":39109,"endToken":39568,"text":"Docket No. EL26-67-000 \n- 6 - \n \n \nregions.  These new transmission services represent a fundamental paradigm shift from \nthe traditional network service and point-to-point transmission service models established \nin Order No. 888 that have been used across the country for the last three decades.  While \nthese services have the potential to facilitate more efficient use and build out of the \ntransmission system, they also contemplate running the system “tighter” than we have \ndone in the past, potentially with more loads on the system served by co-located or \nbehind-the-meter generation, and potentially more use of batteries, load control systems, \nand backup resources to manage demand during system peaks or other stressed \nconditions.  While it is important to identify innovative solutions that can adapt to the \nneeds of the system, the Commission and grid operators must also be careful not to \nimplement changes that create unforeseen reliability risks.  Ultimately, we must find the \nproper balance (and I would argue we are exploring a new balance) between costs of \ninvestments versus reliability.   \n \nThe Commission’s experience in the PJM co-location proceeding highlights the \ncomplexities and challenges of introducing these new transmission services, which have \nsignificant ramifications for system operations, transmission planning, grid reliability, \nmarket dispatch, resource adequacy, and cost allocation.  As the Commission considers \nwhether to expand these transmission services to new types of load and new regions, I \nencourage commenters to address what impacts the introduction of new firm and non-\nfirm transmission products would have in their regions, as well as any relevant \ncharacteristics that might distinguish their regions from the Commission’s findings in the \nPJM co-location docket.  Ultimately, this topic will have direct long-term impacts on how \nfuture transmission systems will be planned and configured, how efficiently future power \nmarkets will operate, and how customers will respond to prices and system needs.  \nTherefore, I am specifically interested in understanding how extending the new \ntransmission services might affect individual suppliers or customers, as well as how \nexisting systems or processes might be affected by these new services.  I am open to \nunderstanding how these services might be helpful to a region or that they may create \nproblems not yet anticipated.   \nV. \nThe Orders Recognize the Importance of Evaluating Advanced Transmission \nTechnologies \n \nLastly, today we preliminarily find that each RTO/ISO’s tariff is unjust and \nunreasonable because the tariff lacks clear and consistent provisions requiring the \nevaluation of alternative transmission technologies as potential solutions to accommodate \nan Eligible Customer’s request for transmission service on behalf of a large load.  \nSpecifically, it is important for RTO/ISOs and transmission owners to evaluate whether \nalternative transmission technologies are feasible in reducing the cost of transmission \nsystem upgrades or allow for a faster timeline for accommodating the transmission \nservice request.  As many transmission owners have explored various alternative"},{"page":108,"startToken":39568,"endToken":39935,"text":"Docket No. EL26-67-000 \n- 7 - \n \n \ntechnologies in pilot projects,8 it is time to roll out all available technologies to reduce \nrisks and costs for customers, as well as help the industry continue to develop new \ntechnologies that can increase the robustness of our transmission system while protecting \ncustomers from higher costs. \nVI. \nConclusion \n \nToday’s orders address some of the most consequential issues currently in the \nindustry and before the Commission.  I hope that these proceedings provide vehicles \nthrough which the Commission can provide much-needed clarity and direction, and it is \nimperative that we build strong and comprehensive records on each issue in each region \nto inform our decision-making.  I therefore encourage all interested parties to fully \nengage and help the Commission navigate these complex, multi-faceted challenges.  Our \nsuccess will ultimately be measured by our shared ability to deliver reliable and \naffordable power to all customers, to ensure new loads can interconnect in a timely \nfashion while paying their fair share of system costs, and to protect existing customers \nagainst adverse reliability or economic impacts.   \n \n8 See, e.g., Increasing Mkt. and Planning Efficiency Through Improved Software, \nEffective Congestion Mitigation with Transmission Topology Optimization at Alliant \nEnergy and ATC, Docket No. AD10-12-016, available at \nhttps://www.ferc.gov/media/effective-congestion-mitigation-transmission-topology-\noptimization-alliant-energy-and-atc (Alliant and ATC were able to save customers \napproximately $24 million over a 12-month period through the use of topology \noptimization); Pablo Ruiz and Derek Brown, “Reliable and Efficient Congestion \nMitigation Using Transmission Reconfigurations,” NewGrid and Evergy presentation \n(Oct. 2022)¸ available at https://www.spp.org/Documents/67968/SAG%20Meeting%20 \nMaterials%2020221007.zip (identifying reconfigurations, had they been implemented, \nwhich could eliminate 98% of overloads and reduce congestion costs by 85% for \ncongestion patterns associated with 10 significant constraints on Evergy’s system); \nPacific Gas & Electric Press Release, PG&E and Smart Wires Enhance Grid Reliability, \nCapacity for Data Centers in San Jose (May 28, 2025), available at \nhttps://investor.pgecorp.com/news-events/press-releases/press-release-details/2025/PGE-\nand-Smart-Wires-Enhance-Grid-Reliability-Capacity-for-Data-Centers-in-San-\nJose/default.aspx (describing PG&E’s deployment of advanced power flow control \ndevices were able to mitigate thermal overloads by up to 34%, enabling an additional 100 \nMW of firm power delivery over existing lines at a congested substation)."},{"page":109,"startToken":39935,"endToken":39949,"text":"Docket No. EL26-67-000 \n- 8 - \n \n \nFor these reasons, I respectfully concur.  \n \n \n________________________ \nJudy W. Chang \nCommissioner"},{"page":110,"startToken":39949,"endToken":40129,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \nPJM Interconnection, L.L.C.  \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. \nAllegheny Electric Cooperative, Inc. \nAmerican Transmission Systems, Incorporated \nAppalachian Power Company \nAtlantic City Electric Company \nBaltimore Gas and Electric Company \nCommonwealth Edison Company \nCommonwealth Edison Company of Indiana, Inc. \nDayton Power and Light Company \nDelmarva Power & Light Company \nDuke Energy Kentucky, Inc. \nDuke Energy Ohio, Inc. \nDuquesne Light Company \nEssential Power Rock Springs, LLC \nHudson Transmission Partners, LLC \nIndiana Michigan Power Company \nJersey Central Power & Light Company \nKentucky Power Company \nKeystone Appalachian Transmission Company \nKingsport Power Company \nLinden VFT, LLC \nMid-Atlantic Interstate Transmission, LLC \nMonongahela Power Company \nNeptune Regional Transmission System, LLC \nNextEra Energy Transmission MidAtlantic Indiana, Inc. \nOhio Power Company \nOhio Valley Electric Corporation \nOld Dominion Electric Cooperative \nPECO Energy Company \nPPL Electric Utilities Corporation \nThe Potomac Edison Company \nPotomac Electric Power Company \nPublic Service Electric and Gas Company \nRockland Electric Company \nSilver Run Electric, LLC \nDocket No. EL26-67-000"},{"page":111,"startToken":40129,"endToken":40521,"text":"Docket No. EL26-67-000 \n- 2 - \n \n \nTrans-Allegheny Interstate Line Company \nTransource West Virginia, LLC \nUGI Utilities, Inc. \nVirginia Electric and Power Company \nWabash Valley Power Association, Inc. \nWheeling Power Company \n \n \n(Issued June 18, 2026) \n \nLACERTE, Commissioner, concurring: \n \n \nI support today’s fleet of show cause orders.  We are at an inflection point in the \nhistory of American energy infrastructure.  The extraordinary and rapid growth of large \nloads in RTOs and ISOs is faster than the current system can handle.  This order charts a \ncourse for addressing the potential gaps and shortcomings in PJM’s Tariff that need to be \nresolved to appropriately respond to this growth, as informed by careful review of the \nthousands of pages of comments received in response to the advance notice of proposed \nrulemaking (ANOPR).1  I write separately to underscore my expectation for RTOs and \nISOs, including PJM, to timely submit their robust, thoughtful, and region-specific \nproposals to address the concerns that we have preliminarily identified in their respective \ntariffs and agreements.  By harnessing your region-specific expertise and creativity to \nbring tailored solutions to the table, together we can efficiently, reliably, and affordably \nintegrate large load, co-located load and generation and/or storage, as well as electrically \nproximate large load onto the transmission system.  I also support the use of alternative \ntransmission technologies to unlock every megawatt of existing capacity from our current \ntransmission system.  We have the technology.  We should use it now to enable faster \ninterconnection of large loads, lower costs to customers, and help prevent cost shifting. \n \nTo that end, and in light of our action in today’s orders, I also ask the state public \nutility commissions—whether they have already approved large load retail tariffs, are in \nthe process of crafting large load retail tariffs, or have yet to embark on this essential \ntariff design process—to take a hard look and ensure their large load retail tariff \nprovisions insulate ratepayers from the negative impacts of data center growth.  \nAdditionally, I expect PJM to design proposals in response to this show cause order that \ndovetail with the efforts on the retail side to implement the Ratepayer Protection Pledge, \n \n1 Interconnection of Large Loads to the Interstate Transmission System, Advance \nNotice of Proposed Rulemaking, Docket No. RM26-4-000, (Oct. 23, 2025) (ANOPR); \nsee also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy (Oct. 23, 2025) \n(Secretary’s Letter)."},{"page":112,"startToken":40521,"endToken":40984,"text":"Docket No. EL26-67-000 \n- 3 - \n \n \nprotect customers, and ensure that large loads cover the costs they incur to integrate with \nthe grid.   \n \nThe stakes here could not be higher and every gambler knows that the secret to \nsurviving is knowing what to throw away and knowing what to keep.2  Today’s orders do \nexactly that—adopting thoughtful proposals that position our nation for success, driving \nmeaningful change, and rejecting the gridlock, half-measures, and failure to plan that \nhave gone on for far too long.  The data center odyssey that we embarked upon first with \nPJM, then SPP, we now aggressively extend to all the RTO/ISO regions.3  Enabling the \nswift and efficient interconnection of large loads to the transmission system while \nmaintaining affordability, reliability, commitment to open access, competitive principles \nand cooperative federalism, will only be achieved through consistent, coordinated action \nand persistence.  But without that first step,4 there is no direction, no forward momentum, \nno journey, and no way to arrive at our future destination.  In the show cause orders we \nissue today, the Commission takes a series of long strides towards our ultimate large load \ninterconnection destination:  we make preliminary findings that the RTO/ISO tariffs, \nincluding PJM may be unjust and unreasonable and/or unduly discriminatory or \npreferential because they lack features necessary to timely, reliably, and safely \ninterconnect and serve new large loads in a way that produces just and reasonable rates. \n \nI commend each commentor for their robust and ongoing responses to the \nconcerns that Secretary Wright and the Commission raised in the ANOPR proceeding.  \nThe comments helped us identify the common issues, common solutions, and individual \ndifferences among the RTOs/ISOs.  We heard a plea for broad flexibility and regionally \ntailored solutions.  And we will strive to work towards those solutions, not through top-\ndown, one-size-fits-all mandates, but through consideration of region-specific proposals.  \nAnd we endeavor to support an appeal for federal policies that build upon rather than \ndisrupt current and planned developments, reflecting state and local processes and \nstakeholder efforts.  Through these individually tailored and region-specific show cause \norders, we are delivering to ensure that our transmission system can accommodate new \nlarge loads in a timely, safe, and reliable manner.  And, importantly, in a manner that \n \n2 Kenny Rogers, The Gambler (United Artists Records 1978). \n3 Interconnection of Large Loads to the Interstate Transmission System, 195 \nFERC ¶ 61,045 at P 2 (2026) (Order Regarding Intent to Act) (citing PJM Co-Location \nOrder, 193 FERC ¶ 61,217; SPP HILL Order, 194 FERC ¶ 61,031; Commonwealth \nEdison Co., 194 FERC ¶ 61,181 (2026); Tri-State Generation and Transmission Ass’n, \n193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025)). \n4 Admittedly, we are further down the road in some regions as compared with \nothers."},{"page":113,"startToken":40984,"endToken":41482,"text":"Docket No. EL26-67-000 \n- 4 - \n \n \nensures benefits and protection for all customers.  Affordability remains a top concern as \nwe proceed forward.   \n \nThe collective voices in the ANOPR comments have shaped our decision to issue \nsix separate individually tailored and region-specific show cause orders, rather than a \nproposed final rule at this time.  But the success of the next phase of this journey rests \nwith you, PJM, and your stakeholders.  We are directing you to expeditiously bring \nforward for our consideration your novel, region-specific solution(s).  Time is of the \nessence.  By inviting you to proceed under FPA section 205, we are giving you \nsignificant perks:  the benefits of first wielder of the pen and the relatively capacious \nstandard under FPA section 205 that allows us to accept a potentially broad range of \nproposals provided they are shown to be just and reasonable and not unduly \ndiscriminatory or preferential.5  We are even giving you flexibility to propose the \nimplementation date for your innovative proposals.  But such freedom comes with great \nand concomitant responsibility.   \n \nThis is not a time to be cavalier and dodge the urgent need to meet the moment.  \nWhile this is a long journey, even so, we must continue to move at breakneck pace to win  \nthe AI race.  So let me be direct.  If you choose not to submit timely, reasonable, non-\ndiscriminatory or preferential, comprehensive, and substantiated proposal(s), as directed \nand as required under our applicable statutes, your deficient response will not go \nunnoticed.  I am prepared to play jurisdictional hardball, if needed.6  This Commission \nhas appropriately exercised considerable restraint in asserting the full scope of our \njurisdiction in these orders.  However, the Commission has very broad jurisdiction over \ntransmission that we will not hesitate to utilize as necessary to ensure that we meet our \nobjectives in all show cause proceedings, including this PJM proceeding we initiate here.  \nIf we find your Tariff is in fact unjust and unreasonable and unduly discriminatory or \n \n5 See, e.g., NRG Power Mktg, LLC v. FERC, 862 FERC 108, 105 (D.C. Cir. 2017) \n(FERC may not employ a rate design that follows “a completely different strategy” than, \nor is “methodologically distinct” from, a proposed rate) (internal quotations omitted); \nOxy USA, Inc. v. FERC, 64 F.3d 679, 692 (D.C. Cir. 1995) (stating that a proposal under \nFPA section 205 “need not be the only reasonable methodology, or even the most \naccurate”); City of Winnfield v. FERC, 744 F.2d 871, at 874-875 (D.C. Cir. 1984) \n(comparing the respective authorities of the Commission and public utilities under \nsections 205 and 206). \n6 16 U.S.C. § 824(b); New York v. FERC, 535 U.S. 17 (2002) (“There is no \nlanguage in the statute limiting FERC’s transmission jurisdiction to the wholesale \nmarket[.]”)) (emphasis in original); id. at 20 (stating that “the FPA authorizes FERC's \njurisdiction over interstate transmissions, without regard to whether the transmissions are \nsold to a reseller or directly to a consumer[.]”)."},{"page":114,"startToken":41482,"endToken":41694,"text":"Docket No. EL26-67-000 \n- 5 - \n \n \npreferential, any failure on your end to provide a sufficient FPA filing or filings to \naddress the large-load-related concerns that we have identified will result in the \nCommission dictating the solutions for you.  I say this not as a threat, but as a statement \nof duty.  While you may not like our remedies—I have often said that the federal \ngovernment generally does not come up with the best solutions—this is an outcome we \nare prepared to pursue given the gravity of the moment and our statutory obligation.  \nNotwithstanding our readiness to step in, it greatly benefits everyone for you to come up \nwith an approach tailored to your region.  \n \nI will end my concurrence where I began:  We have heard your concerns, and, let \nme underscore, now is the time for you to heed ours.  This is an extraordinarily \nconsequential proceeding.  The stakes for reliability, for affordability, and for the \nAmerican ratepayer could not be higher.  We owe it to the public to get this right.  I look \nforward to reviewing and acting as expeditiously as possible on your responses to this \nshow cause order, which I expect will include an FPA section 205 proposal or proposals. \n \nFor these reasons, I respectfully concur. \n \n \n______________________________ \nDavid LaCerte \nCommissioner"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":2595,"startToken":0,"endToken":358},{"p":2,"at":2595,"title":"C. Extending New Transmission Services to Eligible Customers Taking Service on","method":"printed heading","endPage":3,"endAt":31,"startToken":358,"endToken":379},{"p":3,"at":31,"title":"D. Interconnection Customers Serving Electrically Proximate Large Load and Co-","method":"printed heading","endPage":9,"endAt":31,"startToken":379,"endToken":2533},{"p":9,"at":31,"title":"I. 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Definitions","method":"PDF bookmark","endPage":62,"endAt":926,"startToken":24776,"endToken":24897},{"p":62,"at":926,"title":"3. Tariff Provisions","method":"PDF bookmark","endPage":67,"endAt":1797,"startToken":24897,"endToken":27168},{"p":67,"at":1797,"title":"E. Informational Report","method":"PDF bookmark","endPage":69,"endAt":199,"startToken":27168,"endToken":27817},{"p":69,"at":199,"title":"IV. Briefing Questions","method":"PDF bookmark","endPage":103,"endAt":1116,"startToken":27817,"endToken":37617},{"p":103,"at":1116,"title":"I. Overview of Today’s Orders","method":"PDF bookmark","endPage":104,"endAt":1271,"startToken":37617,"endToken":37989},{"p":104,"at":1271,"title":"II. The Commission Needs Good Records to Ensure Reasoned Decision-Making","method":"PDF bookmark","endPage":104,"endAt":2754,"startToken":37989,"endToken":38211},{"p":104,"at":2754,"title":"III. The Commission Needs to Pursue Meaningful Customer Protection","method":"PDF bookmark","endPage":106,"endAt":1280,"startToken":38211,"endToken":38894},{"p":106,"at":1280,"title":"IV. The Commission Needs to Understand the Implications of Extending New Transmission Services to Additional Loads and Regions","method":"PDF bookmark","endPage":107,"endAt":2444,"startToken":38894,"endToken":39464},{"p":107,"at":2444,"title":"V. The Orders Recognize the Importance of Evaluating Advanced Transmission Technologies","method":"PDF bookmark","endPage":108,"endAt":335,"startToken":39464,"endToken":39619},{"p":108,"at":335,"title":"VI. Conclusion","method":"PDF bookmark","endPage":108,"endAt":340,"startToken":39619,"endToken":39620},{"p":108,"at":340,"title":"Conclusion","method":"printed heading","endPage":114,"endAt":1319,"startToken":39620,"endToken":41694}]}