{"document":{"slug":"e-11-isone-el26-72-000","title":"ISO-NE show cause order","issued":"2026-06-18","docket":"EL26-72-000","filer":"FERC","group":"June 18 orders","kind":"order","file":"docs/orders/e-11-isone-el26-72-000.pdf","url":"https://www.ferc.gov/media/e11-el26-72-000","sha256":"af071275199a16d6b6240b1332b2d67d6b4512daed1601bcd5e7ae7002524cb8","pages":115,"tokens":43320,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":118,"text":"195 FERC ¶ 61,215 \nUNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \n \nBefore Commissioners:  Laura V. Swett, Chairman; \n                                        David Rosner, Lindsay S. See, \n                                        Judy W. Chang, and David LaCerte. \n \nISO New England Inc. \nCentral Maine Power Company  \nThe Connecticut Light and Power Company \nFitchburg Gas and Electric Light Company \nGreen Mountain Power Corporation  \nMaine Electric Power Company  \nThe Narragansett Electric Company \nNew England Power Company \nNew Hampshire Transmission, LLC  \nNSTAR Electric Company \nPublic Service Company of New Hampshire \nThe United Illuminating Company  \nUnitil Energy Systems, Inc.  \nVermont Electric Cooperative, Inc. \nVermont Electric Power Company, Inc. \nVermont Transco LLC  \nVersant Power  \nDocket No.\n \nEL26-72-000 \n \n \n \nORDER INSTITUTING PROCEEDING \n  \nUNDER SECTION 206 OF THE FEDERAL POWER ACT \n \n(Issued June 18, 2026)"},{"page":2,"startToken":118,"endToken":294,"text":"Docket No. EL26-72-000 \n- 2 - \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 .............................. 12. \n1. PJM Co-Location Proceedings ............................................................................ 13. \n2. SPP High Impact Large Load and High Impact Large Load Generation \nAssessment Processes .............................................................................................. 16. \n3. SPP Conditional High Impact Large Load Service ............................................. 18. \nII. ISO-NE’s Existing Processes ....................................................................................... 20. \nA. Existing Tariff Processes ......................................................................................... 20. \nB. Recent Stakeholder Proceedings in ISO-NE ........................................................... 30. \nIII. Discussion ................................................................................................................... 32. \nA. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 38. \n1. Jurisdiction ........................................................................................................... 42. \n2. Tariff Provisions .................................................................................................. 48. \nB. Cost Shifting Risk Among Transmission Customers .............................................. 64. \n1. Jurisdiction ........................................................................................................... 66. \n2. Additional Cost Transparency ............................................................................. 69. \n3. Cost Recovery Agreements ................................................................................. 74. \nC. Co-Location Arrangements and Load with Behind the Meter Generation ............. 83. \n1. Definition ............................................................................................................. 85. \n2. Jurisdiction ........................................................................................................... 89. \n3. Tariff Provisions .................................................................................................. 91. \nD. Extending New Transmission Services to Eligible Customers Taking Service on \nBehalf of Flexible Large Loads ................................................................................. 101. \nE. Interconnection Customers Serving Electrically Proximate Large Load and Co-\nLocated Load .............................................................................................................. 104. \nF. Informational Report .............................................................................................. 118. \nIV. Briefing Questions .................................................................................................... 120."},{"page":3,"startToken":294,"endToken":769,"text":"Docket No. EL26-72-000 \n- 3 - \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 Co-\nLocation Order); Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026) (SPP HILL Order); \nSw. Power Pool, Inc., 195 FERC ¶ 61,196 (2026) (SPP CHILLS Order); see also, e.g., \nDuke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025); Commonwealth Edison Co., \n194 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 56. \n3 As explained below, it appears that it would be reasonable to define co-located \nload as a configuration that refers to end-use customer load that is physically connected \nto the facilities of an existing or planned generating facility on the interconnection \ncustomer’s side of the point of interconnection to the RTO/ISO’s transmission system.   \nIn this order, we will use the term co-location arrangement when referring to both the   \nco-located load and the associated generating facility.  See infra P 86. \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 No. \nRM26-4-000 (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, as explained below, we use the \nterm co-located load."},{"page":4,"startToken":769,"endToken":1241,"text":"Docket No. EL26-72-000 \n- 4 - \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, and PJM \nInterconnection, L.L.C. (PJM) has likewise taken steps toward that goal in response to \nthis Commission’s directives.8  By contrast, ISO New England Inc. (ISO-NE) has not yet \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. EL26-72-000. \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 110. \n8 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); SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order,            \n195 FERC ¶ 61,196."},{"page":5,"startToken":1241,"endToken":1639,"text":"Docket No. EL26-72-000 \n- 5 - \nproposed tariff revisions to address the challenges associated with the integration of large \nand co-located loads. \n \nAs discussed below, we find that ISO-NE’s existing Transmission, Markets and \nServices Tariff (Tariff) appears to be unjust, unreasonable, or unduly discriminatory or \npreferential.  We thus institute a show cause proceeding pursuant to section 206 of the \nFederal Power Act (FPA),9 and we direct ISO-NE and the Participating Transmission \nOwners,10 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 Customers11 seeking transmission \nservice on behalf of large loads;  \n \n9 16 U.S.C. § 824e. \n10 Participating Transmission Owners refers to the entities listed in the caption of \nthis order.  We recognize that ISO-NE’s transmission owners include entities that are not \nsubject to the Commission’s jurisdiction because they are not public utilities pursuant to \nsection 201(f) of the FPA.  See 16 U.S.C. § 824(f); Sw. Power Pool, Inc., 180 FERC        \n¶ 61,022, at PP 44-45 (2022).  Accordingly, the Commission has not included Town of \nBraintree Electric Light Department; Chicopee Municipal Lighting Plant; Connecticut \nMunicipal Electric Energy Cooperative; Connecticut Transmission Municipal Electric \nEnergy Cooperative; The City of Holyoke Gas and Electric Department; Town of Hudson \nLight and Power Department; Massachusetts Municipal Wholesale Electric Company; \nTown of Middleborough Gas & Electric Department; New Hampshire Electric \nCooperative, Inc.; Town of Norwood Municipal Light Department; Town of Reading \nMunicipal Light Department; Shrewsbury Electric and Cable Operations; Town of Stowe \nElectric Department; Taunton Municipal Lighting Plant; Vermont Public Power Supply \nAuthority; and Town of Wallingford, CT, Department of Public Utilities, Electric \nDivision here as Participating Transmission Owners that must respond to this order to \nshow cause.  Nonetheless, the Commission retains the authority to review each entity’s \nformula rates as a component of ISO-NE’s Tariff in an order to show cause directed \ntowards ISO-NE, and ISO-NE must respond to this order regarding the non-public \nutilities’ ISO-NE Tariff provisions on file with the Commission.  See Sw. Power Pool, \nInc., 180 FERC ¶ 61,022 at P 40. \n11 ISO-NE’s Tariff defines an Eligible Customer as: \n(i) Any entity that is engaged, or proposes to engage, in the \nwholesale or retail electric power business is an Eligible"},{"page":6,"startToken":1639,"endToken":1991,"text":"Docket No. EL26-72-000 \n- 6 - \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 ISO-NE, 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) the rates, terms, and conditions of service that apply to co-location \narrangements;  \n(d) transmission services that reflect Eligible Customers taking \ntransmission service on behalf of co-located loads, load with behind the \nmeter generation, and flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions;12 and \n \nCustomer under the [Tariff].  (ii) Any electric utility \n(including any power marketer), Federal power marketing \nagency, or any other entity generating electric energy for sale \nor for resale is an Eligible Customer under the [Tariff]. . . .  \n(iii) Any end user taking or eligible to take unbundled \ntransmission service or Local Delivery Service pursuant to a \nstate requirement that the Transmission Owner with which \nthat end user is directly interconnected or the distribution \ncompany having the service territory in which that entity is \nlocated (if that entity is a retail customer) offer the \ntransmission service or Local Delivery Service, or pursuant to \na voluntary offer of such service by the Transmission Owner \nwith which that end user is directly interconnected, or the \ndistribution company having the service territory in which \nthat entity is located (if that entity is a retail customer) is an \nEligible Customer under the [Tariff]. \nISO-NE, Transmission, Markets and Services Tariff, § I.2 (Rules of Construction; \nDefinitions) (177.0.0), § I.2.2 (ISO-NE Tariff). \n12 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 \nwilling and able to limit their energy withdrawals from the transmission system under \ncertain conditions.  See infra note 221."},{"page":7,"startToken":1991,"endToken":2386,"text":"Docket No. EL26-72-000 \n- 7 - \n(e) 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 ISO-NE’s need to ensure adequate generation to serve \nnew large loads.13  We therefore direct ISO-NE to submit, within 30 days of the date of \nissuance of this order, an informational report on how ISO-NE 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 ISO-NE and/or the Participating \nTransmission Owners in response to this proceeding should (a) propose a reasonable \nimplementation period to ensure minimal disruption to such existing commercial \narrangements, and (b) allow a reasonable amount of time to finalize ongoing agreements \nthat are nearing completion as of the date such Tariff provisions are filed with the \nCommission.  Such proposed Tariff revisions should include a reasonable effective date \nthat accommodates such considerations regarding these existing commercial \narrangements. \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 \n \n13 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":8,"startToken":2386,"endToken":2822,"text":"Docket No. EL26-72-000 \n- 8 - \ngrowth of large loads.14  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.15  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.16 \n \nOn April 16, 2026, the Commission issued an order regarding its intent to act with \nrespect to the ANOPR docket.17  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 \nnon-discriminatory manner.’”18  After recognizing the Commission’s recent actions in \nproceedings involving issues associated with large loads,19 the Commission concluded \n \n14 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). \n15 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). \n16 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. \n17 Interconnection of Large Loads to the Interstate Transmission Sys., 195 FERC   \n¶ 61,045 (2026) (Order Regarding Intent to Act). \n18 Id. P 2. \n19 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; Duke Energy Carolinas, LLC,"},{"page":9,"startToken":2822,"endToken":3221,"text":"Docket No. EL26-72-000 \n- 9 - \nthat it was clear that additional “action is warranted to support further progress where it is \nneeded.”20 \n \nISO-NE states that, while New England has not experienced data center proposals \nto the extent seen in other regions of the country to date,21 it is aware of interest in large \nload development within its footprint and is prioritizing preparation for the potential of \nlarge load additions.22  In 2026, in acknowledgement of the potential growth of large \nloads in the region, ISO-NE included a separate projection for large load nameplate \ncapacity for the first time in its Capacity, Energy, Loads, and Transmission (CELT) load \nforecast.23  ISO-NE also recently presented on its efforts to plan for large load growth in \nthe region at the 2026 New England Conference of Public Utilities Commissioners.24  \nEversource notes in its ANOPR comments that the rapid onset of the interconnection of \nlarge loads around the country, especially data center and electrification projects, \nrepresents an unprecedented sea change in the industry.25  Additionally, the Commission \nhas recently accepted several study agreements filed by multiple transmission owners in \nISO-NE that include terms and conditions for conducting studies concerning the viability \nof interconnecting large loads.26  Further, the Southeast PIOs in their ANOPR comments \n \n193 FERC ¶ 61,237). \n20 Id. PP 3-4. \n21 ISO-NE, ISO-NE’s Response to Chairman David Rosner’s September 18, 2025 \nLetter Seeking a Dialogue on Large Load Growth in New England 1 (Oct. 6, 2025), \nhttps://www.iso-ne.com/static-assets/documents/100028/large-load-forecasting-isone-\nresponse.pdf (ISO-NE Letter). \n22 Id.; see also ISO-NE, Final Draft 2026 Large Load Forecast 3 (Mar. 27, 2026), \nhttps://www.iso-ne.com/static-assets/documents/100033/fx2026_large_loads.pdf (noting \nthat there are a couple hundred MW of large loads in the formal study phase) (ISO-NE \nLarge Load Forecast Presentation). \n23 See ISO-NE Large Load Forecast Presentation at 14. \n24 See ISO-NE, Planning for Large Loads in New England (May 20, 2026), \nhttps://www.iso-ne.com/static-\nassets/documents/100035/iso_large_loads_necpuc_symposium_mcbride.pdf.  \n25 Eversource November 21 ANOPR Comments at 2. \n26 See, e.g., NSTAR Elec. Co., Docket No. ER21-2696-000 (Oct. 14, 2021) \n(delegated order); Pub. Serv. Co. of N.H., ER24-2522-000 (Aug. 30, 2024) (delegated \norder); NSTAR Elec. Co., Docket No. ER25-1796-000 (May 27, 2025) (delegated order); \nNSTAR Elec. Co., Docket No. ER25-1795-000 (May 27, 2025) (delegated order); The"},{"page":10,"startToken":3221,"endToken":3618,"text":"Docket No. EL26-72-000 \n- 10 - \ncite to a Report from NESCOE, which states that while the New England area may have \nless data center development currently than areas such as Virginia, data center issues are \nlikely to become more salient in New England as other markets become saturated and \npower and land availability becomes an issue.27  Moreover, recent news articles note \nincreased interest in data center development throughout the region.28   \n \nAlthough some commenters in the ANOPR proceeding assert that ISO-NE’s \nexisting processes effectively facilitate the interconnection of large loads,29 many other \nentities support additional reforms addressing large and co-located loads.  ISO-NE agrees \nthat clear rules should be developed, in part based on its existing processes, for \nintegrating large loads and co-location arrangements onto the transmission system.30  \nEntities in ISO-NE highlight the unique planning and reliability challenges that large and \nco-located loads pose for the region.31  NESCOE states that regulators should prioritize \n \nConn. Light & Power Co., Docket No. ER26-1158-000 (Mar. 18, 2026) (delegated \norder); The Conn. Light & Power Co., Docket No. ER26-1597-000 (Apr. 21, 2026) \n(delegated order). \n27 Southeast PIOs November 21 ANOPR Comments at 36 (citing NESCOE, Data \nCenters and the Power System: A Primer, at 4 (2024), https://nescoe.com/resource-\ncenter/data-centers-primer/). \n28 See, e.g., Jon Lamson, Data Center Interest, Opposition on the Rise in New \nEngland, RTO Insider (Apr. 2, 2026), https://www.rtoinsider.com/129446-data-center-\ninterest-opposition-on-the-rise-new-england/#/; Patrick Anderson, Why RI Now Finds \nItself in the Center of the Data Center Debate, The Providence Journal (Apr. 20, 2026), \nhttps://www.providencejournal.com/story/news/politics/state/2026/04/20/ri-debates-\nbuilding-and-regulating-data-centers-starting-in-smithfield/89594859007/; Sabrina \nShankman, An Economic Opportunity, or an Energy Crisis in Waiting? Data Centers Are \nComing to Massachusetts, Boston Globe (Jun. 6, 2025), \nhttps://www.bostonglobe.com/2025/06/06/science/an-economic-opportunity-or-an-\nenergy-crisis-waiting-data-centers-are-coming-massachusetts/. \n29 See New England Consumer-Owned Systems November 21 ANOPR Comments \nat 22 (“To the extent that large-load development accelerates in New England, the region \nalready has a mature, carefully tailored set of interconnection requirements that reflect \nunique reliability characteristics, transmission constraints, and long-standing market \ndesign.”); see also Eversource November 21 ANOPR Comments at 5-6 (“In Eversource’s \nexperience, prospective large loads overwhelmingly prefer the retail construct.”). \n30 ISO-NE November 21 ANOPR Comments at 2. \n31 NESCOE November 21 ANOPR Comments at 2-3, 12; New England \nConsumer-Owned Systems November 21 ANOPR Comments at 26-27 (noting that the"},{"page":11,"startToken":3618,"endToken":3951,"text":"Docket No. EL26-72-000 \n- 11 - \nmaintaining grid reliability and energy affordability.32  New England Consumer-Owned \nSystems assert that the Commission should adopt safeguards to ensure that large and    \nco-located loads are integrated onto the transmission system without introducing \nunacceptable reliability concerns.33  Additionally, National Grid states that its own \nexperience in New England has confirmed the need to define the rules for large load \ninterconnections, and supports reforms that capture the efficiencies of generation paired \nwith electrically proximate large load.34   \n \nSome entities are also concerned with protecting ratepayers from cost shifts \ncaused by large and co-located loads.35  National Grid states that innovative solutions to \nintegrate large loads will reduce the amount of system upgrades required, which will in \nturn benefit existing ratepayers by exposing them to less risk of higher costs associated \nwith new upgrades.36  Other commenters argue that the Commission should provide \nmechanisms for additional load flexibility.37  New England Consumer-Owned Systems \nalso highlight the potential for co-location arrangements to avoid certain wholesale \ncharges, including transmission and ancillary services charges.38   \n \nMoreover, many commenters in the ANOPR proceeding filed persuasive \ncomments documenting, generally, the need for clear and consistent tariff provisions to \n \nrisks of large load are particularly acute in New England because ISO-NE has significant \ntransmission constraints and has a system peak that is only approximately 30,000 MW, \nsuch that the consequences of large or co-located loads improperly operating could be \nsevere). \n32 NESCOE November 21 ANOPR Comments at 2-3. \n33 New England Consumer-Owned Systems November 21 ANOPR Comments at \n26-27. \n34 National Grid November 21 ANOPR Comments at 2-3, 17-18. \n35 Maine Public Advocate November 21 ANOPR Comments at 2; New England \nConsumer-Owned Systems November 21 ANOPR Comments at 4, 19-20; State Entities \nNovember 21 ANOPR Comments at 7-8. \n36 National Grid November 21 ANOPR Comments at 2-3. \n37 Maine Public Advocate November 21 ANOPR Comments at 4-5; State Entities \nNovember 21 ANOPR Comments at 8. \n38 New England Consumer-Owned Systems November 21 ANOPR Comments at \n13-14."},{"page":12,"startToken":3951,"endToken":4400,"text":"Docket No. EL26-72-000 \n- 12 - \nensure regulatory and process certainty, fairness and consistency, and efficiency as large \nand co-located loads are added to the transmission system in increasing numbers.39  \nThere is also broad support for rules that help to ensure that other transmission customers \nare not unfairly burdened with additional costs or reliability impacts as large and co-\nlocated loads interconnect to the transmission system.40  In addition, many ANOPR \ncommenters highlighted the need to efficiently integrate large loads, particularly data \ncenters, to support national security priorities and economic development.41   \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 20542 filings, the growing use of co-location \narrangements.43  The Commission’s orders in those proceedings have addressed the need \n \n39 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 November \n21 ANOPR Comments at 3-4; ECA November 21 ANOPR Comments at 7-11; EPSA \nNovember 21 ANOPR Comments at 4-6; Infrastructure Masons December 5 ANOPR \nComments at 4-7; Microsoft November 21 ANOPR Comments at 9-10; National Grid \nNovember 21 ANOPR Comments at 7; ODEC December 5 ANOPR Comments at 2-4;   \nR Street November 21 ANOPR Comments at 3; Switch December 5 ANOPR Comments \nat 3; Tract November 21 ANOPR Comments at 5; Vantage November 21 ANOPR \nComments at 5-6; Vistra December 5 ANOPR Comments at 1-2. \n40 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 November \n21 ANOPR Comments at 3; OCC November 21 ANOPR Comments at 9; Oklo \nDecember 5 ANOPR Comments at 3; Southeast PIOs December 5 ANOPR Comments \n11-15; State Entities November 21 ANOPR Comments at 7-8; Tri-State November 21 \nANOPR Comments at 8; UCS November 21 ANOPR Comments at 9-11; U.S. \nRepresentatives November 21 ANOPR Comments at 1. \n41 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 at \n6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR \nComments at 2-3; Verrus December 5 ANOPR Comments at 2. \n42 16 U.S.C. § 824d. \n43 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 ¶"},{"page":13,"startToken":4400,"endToken":4815,"text":"Docket No. EL26-72-000 \n- 13 - \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 co-\nlocation arrangements become more common.  It is in this context that the Commission \nnow considers whether ISO-NE’s Tariff remains just and reasonable without similar \nprovisions. \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 \nto co-location arrangements.44  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.45  On December \n18, 2025, the Commission found that PJM’s tariff was indeed unjust and unreasonable \nbecause it does not contain provisions addressing with sufficient clarity or consistency \nthe rates, terms, and conditions of service that apply to interconnection customers serving \nco-located load and Eligible Customers taking transmission service on behalf of co-\nlocated load.46   \n \n61,209; SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ 61,196. \n44 See PJM Show Cause Order, 190 FERC ¶ 61,115. \n45 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.   \n46 PJM Co-Location Order, 193 FERC ¶ 61,217."},{"page":14,"startToken":4815,"endToken":5189,"text":"Docket No. EL26-72-000 \n- 14 - \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.47  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.48  Additionally, the Commission found that PJM’s behind the meter \ngeneration rules were no longer just and reasonable.49  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;50 (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 constructed \n(interim NITS); (b) a new firm contract demand transmission service; or (c) a new non-\nfirm contract demand transmission service;51 (3) to revise the behind the meter generation \nrules and implement a transition process for existing behind the meter generation \nparticipants;52 and (4) to make several clarifications on how certain aspects of PJM’s \ngenerator interconnection process apply to interconnection customers seeking to serve   \nco-located load.53   \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 \n \n47 Id. P 176.  \n48 Id. P 177. \n49 Id. P 179. \n50 Id. PP 187-192, 225-230. \n51 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 219-20. \n52 Id. PP 221-224.  \n53 Id. PP 161, 231-36."},{"page":15,"startToken":5189,"endToken":5576,"text":"Docket No. EL26-72-000 \n- 15 - \nconditions for the new transmission services (i.e., interim NITS, firm contract demand \ntransmission service, and non-firm contract demand transmission service).54 \n2. \nSPP High Impact Large Load and High Impact Large Load \nGeneration 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.55  SPP’s tariff revisions established HILLs as a new \ncategory of load;56 imposed enhanced study requirements to enable SPP to assess the \nHILL’s reliability impacts on the transmission system;57 and created additional, ongoing \noperational requirements for transmission customers serving HILLs to ensure continued \nreliability of the transmission system.58  The tariff revisions also established the HILLGA \n \n54 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). \n55 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64.   \n56 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 \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 (Definitions \nH) (1.0.0). \n57 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). \n58 Id. P 18 (explaining that market participants registering a HILL must (1) follow"},{"page":16,"startToken":5576,"endToken":5997,"text":"Docket No. EL26-72-000 \n- 16 - \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.59   \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.”60  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.61  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.62  In addition, the Commission found that the proposed study \ndeposits would discourage speculative HILL study requests.63  Finally, the Commission \n \nall nonconforming load requirements (e.g., additional load forecast requirements); (2) \nprovide load data via telemetry in real time; (3) have remote capability to disconnect the \nload from the transmission system made available to the transmission operator; (4) have \nan up/down ramp rate not exceeding 20 MW per minute unless otherwise directed; (5) \ninclude additional information with registration; and (6) not have withdrawals from the \ntransmission system without appropriate transmission service); id. P 19 (explaining that \nthe transmission owner, at the transmission customer’s expense, must install a phasor \nmeasurement unit or similar equipment); id. PP 20-21 (explaining that the transmission \ncustomer will be required to comply with ride-through requirement guidelines). \n59 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).  \n60 Id. P 60. \n61 Id. P 61. \n62 Id. P 62. \n63 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"},{"page":17,"startToken":5997,"endToken":6320,"text":"Docket No. EL26-72-000 \n- 17 - \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.64  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.”65   \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(CHILLS).66  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.67  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.68  \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.69   \n \nThe Commission found that SPP had shown that unprecedented growth in large \nloads presents significant and unique operational and planning challenges.70  The \nCommission also found that SPP’s ability to add HILLs to its transmission system in a \n \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. \n64 Id. P 63. \n65 Id. P 64. \n66 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. \n67 Id. P 7.  \n68 Id. PP 9-10. \n69 Id. P 9. \n70 Id. P 84."},{"page":18,"startToken":6320,"endToken":6673,"text":"Docket No. EL26-72-000 \n- 18 - \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.71  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.72 \nII. \nISO-NE’s Existing Processes \nA. \nExisting Tariff Processes \n \nISO-NE’s Tariff sets forth the processes by which an Eligible Customer may \nrequest Regional Network Service, Local Network Service, and firm or non-firm Local \nPoint-to-Point Service.  Regional Network Service73 is transmission service over Pool \nTransmission Facilities (PTF) provided by ISO-NE to Network Customers74 to serve \ntheir loads.75  Network Customers taking Regional Network Service must also take Local \nNetwork Service.76 \n \nIn order for ISO-NE to provide Regional Network Service to any Eligible \nCustomer, (1) the Eligible Customer must submit an application for Regional \nTransmission Service (which includes a request to recognize a new Regional Network \nLoad); (2) the Eligible Customer and ISO-NE complete the technical arrangements set \nforth in sections II.16.3 and II.16.4 of ISO-NE’s Tariff; and (3) the Eligible Customer \nmust either have an executed (or a filed unexecuted) Market Participant Service \n \n71 Id. \n72 Id. \n73 ISO-NE Tariff, § II.11 (Nature of Regional Network Service) (2.0.0). \n74 Network Customer is a “Transmission Customer receiving [Regional Network \nService] or [Local Network Service].”  Id. § I.2.2.  A Transmission Customer is “any \nEligible Customer that (i) executes, on its own behalf or through its Designated Agent, an \n[Market Participant Service Agreement] or [Transmission Service Agreement]” or \nrequests to file an unexecuted agreement.  Id. \n75 PTF are transmission facilities rated 69 kV or above required to allow energy \nfrom significant power sources to move freely on the New England Transmission System \nowned by Participating Transmission Owners, and operated by ISO-NE.  See id. § II.49 \n(Definition of PTF) (2.0.0).  \n76 See id. § II.23 (Application of Part II.B to Transmission Customers) (0.0.0)."},{"page":19,"startToken":6673,"endToken":7061,"text":"Docket No. EL26-72-000 \n- 19 - \nAgreement, or have an executed (or request a filed unexecuted) Service Agreement for \nRegional Network Service.77   \n \nWhen an Eligible Customer requests Regional Network Service, ISO-NE reviews \nthe effect of the requested service on the reliability requirements to meet existing and \npending obligations of any affected transmission owner(s) and on the obligations of the \nparticular Participating Transmission Owner and determines whether evaluation as part of \na Cluster Study is needed.78  The Cluster Study is also used to process all requests for \ngenerator interconnection service, as well as to process requests made under ISO-NE’s \nElective Transmission Upgrade Interconnection Procedures.79  An Eligible Customer \nseeking transmission service on behalf of load must execute a Cluster Study Agreement \nand submit it to ISO-NE, together with study and commercial readiness deposits and \ntechnical data required of new requests for Network Resource Interconnection Service by \nSchedule 22 (for requests greater than 20 MW) and Schedule 23 (for requests up to 20 \nMW).80  The Cluster Study consists of a short circuit analysis, a stability analysis, a \npower flow analysis, such as electromagnetic transient analysis, including thermal \nanalysis and voltage analysis, a system protection analysis, and any other analyses that \nare deemed necessary by ISO-NE in consultation with the interconnecting transmission \nowner.81   \n \nIf ISO-NE finds that it is likely that a Direct Assignment Facility82 will be \nrequired, a portion of the Cluster Study evaluation shall be performed by the affected \n \n77 Id. § II.16 (Initiating Service) (1.0.0); id. attach. B (Service Agreement for \nRegional Network Service) (1.0.0). \n78 Id. § II.19 (Study Procedures for Regional Network Service Requests) (3.0.0), \nII.19.1, II.19.2. \n79 Id. Schedule 25 (Elective Transmission Upgrade Interconnection Procedures) \n(12.0.0), § 3.3.2. \n80 Id. § II.19.1; see also id. Schedule 22 (Large Generator Interconnection \nProcedures) (26.0.0), § 7.2.; id. Schedule 23 (Small Generator Interconnection \nProcedures) (23.0.0), § 7.2. \n81 Id. Schedule 22, § 7.3. \n82 Direct Assignment Facilities are defined in part as “facilities or portions of \nfacilities that are constructed for the sole use/benefit of a particular Transmission \nCustomer requesting service under the [Tariff] or a Generator Owner requesting an \ninterconnection.  Direct Assignment Facilities . . . shall be paid for by the [Transmission] \nCustomer.”  Id. § I.1.2."},{"page":20,"startToken":7061,"endToken":7469,"text":"Docket No. EL26-72-000 \n- 20 - \nParticipating Transmission Owner(s), subject to review by ISO-NE.83  If ISO-NE \ndetermines that network upgrades are needed to accommodate the Eligible Customer’s \nrequest for Regional Network Service, ISO-NE, the transmission owner, or a third party \nconsultant for the interconnection customer will conduct a Facilities Study.84  The costs \nof the network upgrades needed to accommodate the Eligible Customer’s request for \nRegional Network Service will be allocated to the Eligible Customer in the same manner \nthat the costs of upgrades to accommodate generating facilities are allocated pursuant to \nSchedule 11 of the Tariff.85  The cost responsibility for network upgrades identified as \nneeded to support requests for Regional Transmission Service are allocated to the \ntransmission Customer as follows:  (1) if the network upgrade is found to be a Cluster \nEnabling Transmission Upgrade,86 the costs are allocated based on the request’s relative \ndistribution impact in the cluster;87 or (2) if the network upgrade is not a Cluster Enabling \nTransmission Upgrade, the costs for System Network Upgrades are allocated based on \nthe request’s proportional impact on the need for such upgrade, and the costs for \nSubstation Network Upgrades shall be allocated first per capita for each Interconnection \nFacility interconnecting to the substation at the same voltage level, then per capita to each \ngenerating facility or Elective Transmission Upgrade Interconnection Customer sharing \nthe Interconnection Facility.88   \n \nNetwork Customers must follow certain operating arrangements, terms, and \nconditions.89  For example, the Tariff requires that ISO-NE, the applicable Participating \n \n83 Id. § II.19.1. \n84 Id. § II.19.2. \n85 Id. § II.19.4. \n86 A Cluster Enabling Transmission Upgrade is new significant transmission line \ninfrastructure that is identified in the Cluster Enabling Transmission Upgrade Regional \nPlanning Study conducted in accordance with Tariff Section II, Attachment K.  A Cluster \nEnabling Transmission Upgrade Regional Planning Study is, in turn, carried out to enable \ninterconnection requests when either (1) two or more interconnection requests have been \nwithdrawn from a Cluster Study Process in the same electrical part of the New England \ncontrol Area, or (2) procurements are underway for resources in the same electrical part \nof the New England Control Area.  See id. Schedule 22, §§ 1, 4.2.1; id. Schedule 23,     \n§§ 1, 4.2.1; id. Schedule 25, §§ 1, 4.2.1.  \n87 Id. Schedule 11 (6.0.0), § 5(i). \n88 Id. Schedule 11, § 5(ii)(1)(a-b). \n89 Id. § II.22 (Operating Arrangements) (2.0.0)."},{"page":21,"startToken":7469,"endToken":7859,"text":"Docket No. EL26-72-000 \n- 21 - \nTransmission Owner(s), and the Network Customer operate and maintain equipment \nnecessary for integrating the Network Customer within the PTF (including, but not \nlimited to, remote terminal units, metering, communications equipment, and relaying \nequipment).90  The Network Customer also has a reporting obligation to respond \npromptly and completely to ISO-NE’s and the applicable Participating Transmission \nOwners’ reasonable requests for information, including, but not limited to, data necessary \nfor operations, maintenance, regulatory requirements, and analysis.91  Under emergency \nsystem operations, the Network Customer’s equipment and facilities are subject to all \napplicable emergency operation standards required of and by ISO-NE to operate in an \ninterconnected transmission network.92  The Tariff also allows ISO-NE to take whatever \nactions it deems necessary during emergency operating conditions to:  (i) preserve the \nintegrity of its transmission system; (ii) limit or prevent damage; (iii) expedite restoration \nof service; or (iv) preserve public safety.   \n \nNetwork Customers pay a charge that covers both local transmission and the costs \nof regional transmission.  For local transmission costs, Network Customers pay a \nmonthly rate calculated by determining a cost allocation factor based on the customer’s \ncoincident peak for the month multiplied by the Local Network rate for the area in which \nthe customer takes service.93  For regional transmission charges, Network Customers are \nallocated a Regional Network Service charge, which is determined by combining the \nannual transmission revenue requirements for the transmission owners of regional PTF \nand dividing by the average 12-month coincident peak for the region.94  \n \nLocal Network Service and Local Point-To-Point Service are Local Transmission \nServices, which are transmission services provided by Participating Transmission Owners \nover non-PTFs to transmission customers.95  Eligible Customers may request Local \nTransmission Service through the Local Service processes in Schedule 21 of the ISO-NE \n \n90 Id. § II.22.2. \n91 Id. § II.22.2(c). \n92 Id. § II.22.2(i). \n93 Id. § II.21 (Rates and Charges) (8.0.0), II.21.1-2. \n94 Id. Schedule 9 (Regional Network Service) (5.0.0).  PTFs include both existing \ntransmission assets that benefit the regional network as well as new regional transmission \nplanned to meet reliability and economic needs.  Id. § II.49. \n95 Id. Schedule 21 (Local Service) (15.0.0), §§ I (Local Point-to-Point Service), II \n(Local Network Service).  Non-PTFs are local transmission facilities owned and operated \nby local transmission owners."},{"page":22,"startToken":7859,"endToken":8179,"text":"Docket No. EL26-72-000 \n- 22 - \nTariff.  Each Participating Transmission Owner has its own Schedule 21 provisions filed \nin the ISO-NE Tariff specific to that Participating Transmission Owners’ facilities.  \nStudies performed to support Local Service requests are administered by the applicable \nParticipating Transmission Owner as the transmission service provider.  The transmission \ncustomer must agree to compensate the Participating Transmission Owner for any \nnecessary transmission facility additions.96  Local Network Upgrades and Direct \nAssignment Facilities costs are charged to the transmission customer.97  Transmission \ncustomers must execute a Local Service Agreement prior to initiating Local Transmission \nService.98 \n \nIn addition, Market Participants and Participating Transmission Owners must \nsubmit to ISO-NE for approval a Proposed Plan Application99 for:  (i) any additions or \nchanges to resources or facilities under its control; and (ii) any new or materially changed \nplan for action, excluding deactivations or reductions in capacity for resources, that may \nhave a significant adverse impact on the regional power system.100  ISO-NE then \nconducts a “do no harm” reliability review to ensure the proposal does not have a \nsignificant adverse reliability impact prior to allowing the project to proceed.  In \nperforming electric planning and reliability studies, ISO-NE relies on the CELT Report \nas the primary source of assumptions.  ISO-NE’s Transmission Planning Technical Guide \nindicates that specific large proposed loads, such as data centers and large green house \nfacilities, are not generally included in the CELT load forecast but may be included in a \nstudy such as the Proposed Plan Application depending on “the degree of certainty that \n \n96 Id. Schedule 21, §§ I.14, II.7.d. \n97 Id. Schedule 21, §§ I.1.e, II.9. \n98 Id. Schedule 21, §§ I.4.a.vi, II.3.a, attach. A (Form of Local Service \nAgreement). \n99 See ISO-NE, Proposed Plan Applications, https://www.iso-ne.com/system-\nplanning/transmission-planning/proposed-plan-applications. \n100 ISO-NE Tariff, § I.3 (Obligations of MPs and Other Customers) (10.0.0),         \n§ I.3.9."},{"page":23,"startToken":8179,"endToken":8579,"text":"Docket No. EL26-72-000 \n- 23 - \nthe large proposed load will come to fruition.”101  As we note above, however, a forecast \nof large load capacity was included in the latest 2026-2035 CELT Report.102 \n \nISO-NE processes large generator interconnection requests under Schedule 22 of \nits Tariff (Standard Large Generator Interconnection Procedures) and small generator \ninterconnection requests under Schedule 23 of its Tariff (Standard Small Generator \nInterconnection Procedures).103  ISO-NE processes both small and large generators in a \nsingle, integrated Cluster Study process.  First, ISO-NE conducts a Cluster Study to \nevaluate the impact of the proposed interconnection on the reliability and operation of the \nNew England Transmission System to identify the interconnection facilities and network \nupgrades that are required to reliably interconnect the generating facilities in that Cluster \nStudy and a non-binding good faith estimate of cost responsibility.104  Next, ISO-NE may \nconduct a Cluster Restudy if one or more interconnection customers withdraw from the \ncluster, the scope of which is consistent with the scope of an initial Cluster Study.105  \nFinally, ISO-NE may conduct an Interconnection Facilities Study for each \ninterconnection request to specify and provide a non-binding estimate of the cost of the \nequipment, engineering, procurement, and construction work needed to implement the \nconclusions of the Cluster Study report and electrically connect the interconnection \nfacilities to the transmission system, unless the interconnection customer(s) elects to \nwaive the facilities study.106   \n \nPursuant to the Tariff, an interconnection customer may request, and ISO-NE may \nprovide, provisional interconnection service enabling the receipt of electric energy \ncapability from the generating facility at the point of interconnection on a limited and \ntemporary basis prior to completion of requisite interconnection facilities, network \n \n101 See ISO-NE, Transmission Planning Technical Guide § 2.2.3 (May 23, 2025), \nhttps://www.iso-ne.com/static-\nassets/documents/100023/transmission_planning_technical_guide_rev8_3_final.pdf. \n102 See supra P 8. \n103 ISO-NE Tariff, Schedule 22 (26.0.0), § 7.2.; id. Schedule 23 (23.0.0), § 7.2. \n104 Id. Schedule 22, § 7.3; see also id. Schedule 23, § 7.3 (Scope of Cluster Study). \n105 Id. Schedule 22, § 7.5 (Cluster Study Restudies); see also id. Schedule 23, § 7.5 \n(Cluster Study Restudies). \n106 Id. Schedule 22, §§ 8.1 (Interconnection Facilities Study Agreement), 8.2 \n(Scope of Interconnection Facilities Study); see also id. Schedule 23, §§ 8.1 \n(Interconnection Facilities Study Agreement), 8.2 (Scope of Interconnection Facilities \nStudy)."},{"page":24,"startToken":8579,"endToken":8939,"text":"Docket No. EL26-72-000 \n- 24 - \nupgrades, distribution upgrades, or system protection facilities.107  In evaluating a request \nfor provisional interconnection service, ISO-NE and the Interconnecting Transmission \nOwner shall determine, through available studies or additional studies as necessary, \nwhether stability, short circuit, thermal, and/or voltage issues would arise if \ninterconnection customer interconnects without modifications to the generating facility or \nthe New England Transmission System.  An interconnection customer may also request, \nand ISO-NE may provide, surplus interconnection service for unused capability of \ninterconnection service at an existing point of interconnection.108  Studies for surplus \ninterconnection service may consist of reactive power, short circuit/fault duty, stability \nanalyses, and/or other appropriate studies, and steady-state (thermal/voltage) analyses \nmay also be performed as necessary to ensure that all required reliability conditions are \nstudied.109   \nB. \nRecent Stakeholder Proceedings in ISO-NE \n \nISO-NE recently indicated that it is engaging with transmission owners regarding \npotential large load interconnections, and that it is communicating with states to \nunderstand any potential policies creating incentives for data centers and to share \ninformation on how ISO-NE would review such proposed developments.110  \nAdditionally, ISO-NE explained that it participates in several interregional initiatives on \nlarge loads as well as the upcoming NERC Large Load Task Force.111  ISO-NE’s \nConsumer Liaison Group met on June 2, 2026 to discuss data center issues.112  Finally, \nalthough not directly related to large and co-located loads, ISO-NE is currently engaged \nwith stakeholders to better address seasonal reliability challenges and to more accurately \nreflect resource contributions to resource adequacy.113 \n \n107 Id. Schedule 22, app. 11, art. 5.9.2 (Provisional Interconnection Service); see \nalso id. Schedule 23, app. 11, art. 1.6.3 (Provisional Interconnection Service). \n108 Id. Schedule 22, § 3.3 (Utilization of Surplus Service); see also id. Schedule 23 \n§ 3.3 (Utilization of Surplus Interconnection Service). \n109 Id. Schedule 22, § 3.3.1; see also id. Schedule 23, § 3.3.1. \n110 ISO-NE Letter at 1-2. \n111 Id. at 3. \n112 Jon Lamson, ISO-NE Consumer Liaison Group Talks Data Center Impacts, \nRTO Insider (June 7, 2026), https://www.rtoinsider.com/133689-iso-ne-consumer-\nliaison-group-talks-data-center-impacts/. \n113 See ISO-NE, Capacity Auction Reforms Key Project, https://www.iso-"},{"page":25,"startToken":8939,"endToken":9246,"text":"Docket No. EL26-72-000 \n- 25 - \n \nWhile we are encouraged by ISO-NE’s stakeholder efforts, and by its initial \nattention to the pressing concerns associated with large and co-located loads114 and to the \nSecretary’s interest in these issues,115 we are initiating this FPA section 206 proceeding \nin order to ensure that ISO-NE’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 ISO-NE 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 \nISO-NE and the Participating Transmission Owners, within 60 days of the date of this \norder, 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 ISO-NE, 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) the rates, terms, and conditions of service that apply to co-location \narrangements;  \n(d) transmission services that reflect Eligible Customers taking \ntransmission service on behalf of co-located loads, load with behind the \n \nne.com/committees/key-projects/capacity-auction-reforms-key-project. \n114 See id. at 1. \n115 See supra PP 6-7."},{"page":26,"startToken":9246,"endToken":9697,"text":"Docket No. EL26-72-000 \n- 26 - \nmeter generation, and flexible large loads that are willing and able to limit \ntheir use of the transmission system under certain conditions; and \n(e) 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 also direct ISO-NE to submit, within 30 days of the date of issuance of this \norder, an informational report on how ISO-NE intends to ensure that adequate generation \nwill be available to serve existing and new large loads.   \n \nInterested entities may respond within 30 days of ISO-NE’s and the Participating \nTransmission Owners’ filings, addressing either or both of:  (1) whether the existing \nTariff remains just and reasonable and not unduly discriminatory or preferential; and    \n(2) if not, what changes to the Tariff should be implemented as replacement rates.   \n \nWe recognize that ISO-NE and/or the Participating Transmission Owners (to the \nextent the matters addressed herein implicate aspects of the Tariff over which they have \nthe filing rights) may elect to address some or all of the issues discussed in this order by \nproposing revisions to the Tariff pursuant to their applicable FPA section 205 filing \nrights.  We strongly encourage this.  Although both the Secretary’s ANOPR and our own \nOrder Regarding Intent to Act expressly recognized (and indeed encouraged) that \npossibility,116 no such filings were received from ISO-NE by the Commission prior to the \nissuance of this order.  Should ISO-NE and/or the Participating Transmission Owners \nelect to make such filings in response to this order, those filings should state explicitly \nthat the proposals are being submitted under FPA section 205.  Should ISO-NE and/or \nthe Participating Transmission Owners submit a filing under FPA section 205, they \nshould also explain which of the Commission’s above directives their filing addresses \nand how it resolves them.  Additionally, any such filing should provide a reasoned \nexplanation for how the proposal will avoid disrupting existing commercial arrangements \nand clearly identify a reasonable effective date that accommodates such existing \ncommercial arrangements. \n \nThe Commission will consider requests from ISO-NE and/or the Participating \nTransmission Owners to hold, for up to 90 days, all or certain aspects of this FPA section \n206 proceeding 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 \n \n116 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5."},{"page":27,"startToken":9697,"endToken":10156,"text":"Docket No. EL26-72-000 \n- 27 - \nconsidered to provide ISO-NE and the Participating Transmission Owners time while \nthey work through the stakeholder processes to develop FPA section 205 filings to revise \nthe Tariff to address the issues raised in this order.  Requests for a full or partial \nabeyance117 should be submitted prior to the deadline to respond to this order, \nspecifically within 45 days of issuance of this order, to allow time for the Commission to \nact on the abeyance request.  We emphasize that we will not grant such abeyances \nreflexively, that any abeyance will be limited to 90 days, and that we will look with great \ndisfavor toward requests to extend the abeyance period.  We anticipate that successful \nabeyance requests, if any, will include both (1) a robust description of the content of a \npotential future filing under FPA section 205 and (2) a reasoned and specific explanation \nof when such a filing is expected to 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.118  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 ISO-NE’s Tariff appears to be unjust \nand unreasonable because it lacks provisions that address, with sufficient clarity and \nconsistency, how ISO-NE and/or the Participating Transmission Owners will timely \nstudy (i.e., within 60-90 days of receiving the request) the provision of transmission \nservice to Eligible Customers on behalf of large loads.119   \n \n117 A partial abeyance may be appropriate to the extent ISO-NE is developing FPA \nsection 205 filings in response to only a subset of the directives in this order.  For any \nremaining directives, we expect a response to this order within the 60-day deadline set \nforth herein.  \n118 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). \n119 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":28,"startToken":10156,"endToken":10606,"text":"Docket No. EL26-72-000 \n- 28 - \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 \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 ISO-NE and the Participating Transmission Owners, to the extent the \nmatters addressed herein implicate aspects of the Tariff over which they have the filing \nrights, to explain whether the Tariff remains just and reasonable without an application \nprocess, study procedures, and ongoing operational requirements that address the unique \ncharacteristics and challenges of providing transmission service to Eligible Customers on \nbehalf of large loads, or to propose appropriate Tariff revisions.    \n \nWe acknowledge that our concerns, described below, may not be as urgent in the \nISO-NE region as in other RTOs/ISOs, but the record indicates that there have been, and \nthere is potential for an increase in, requests for transmission service by Eligible \nCustomers on behalf of large loads.120  Additionally, we note that the record indicates \nthat the more limited growth of large loads in the ISO-NE region may be due to the lack \nof a clear and consistent process in ISO-NE’s Tariff for how ISO-NE and/or the \nParticipating Transmission Owners will study the provision of transmission service to \nEligible Customers on behalf of large loads.121  Given the unique challenges that \nproviding transmission service to Eligible Customers on behalf of large loads poses for \nensuring just and reasonable rates, as well as for potentially maintaining reliable \noperation of the transmission system should the growth of large loads in the region \nincrease, we remain concerned that ISO-NE’s Tariff appears to be unjust and \nunreasonable without provisions addressing how ISO-NE and/or the Participating \nTransmission Owners will study the provision of transmission service to Eligible \nCustomers on behalf of large loads with sufficient clarity and consistency.   \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 \n \n120 See supra P 8. \n121 See National Grid November 21 ANOPR Comments at 2-3 (noting the need to \ndefine “rules of the road” for large load interconnection)."},{"page":29,"startToken":10606,"endToken":11060,"text":"Docket No. EL26-72-000 \n- 29 - \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.122   \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.123 \n \nThe Commission is a creature of statute and has jurisdiction over only those \nmatters that Congress has given it the authority to regulate.124  That authority includes \njurisdiction over the wholesale sale and transmission of electricity in interstate \ncommerce, including all facilities used for such sale and transmission.125  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.126  \n \n122 See generally NARUC April 14 ANOPR Comments (highlighting action taken \nby state public utility commissions related to large loads). \n123 Under the pro forma OATT, Eligible Customers include end-use customers \nseeking unbundled retail transmission service, pursuant to state law or public utility’s \nvoluntary offer of such service.  Pro forma OATT, § 1.12 (Definitions – Eligible \nCustomer); see also ISO-NE Tariff, § I.2 (Rules of Construction; Definitions) (177.0.0), \n§ I.2.2. \n124 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). \n125 16 U.S.C. § 824(b)(1). \n126 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,"},{"page":30,"startToken":11060,"endToken":11494,"text":"Docket No. EL26-72-000 \n- 30 - \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.127  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,128 including the \ninterconnection of wholesale load to the transmission system.129  \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 \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 Eligible \nCustomers on behalf of large loads, the costs of which are included in transmission rates.  \nAs such, this study process directly affects Commission-jurisdictional transmission \nrates.130  The Commission has exclusive authority to ensure that the process to study the \n \nlimiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the \nwholesale rate’” (cleaned up)).    \n127 New York v. FERC, 535 U.S. 1, 17, 19-20 (2002) (upholding the Commission’s \nexercise of jurisdiction over unbundled retail transmission service). \n128 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). \n129 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). \n130 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.”)."},{"page":31,"startToken":11494,"endToken":11957,"text":"Docket No. EL26-72-000 \n- 31 - \nprovision of transmission service to Eligible Customers is just and reasonable and not \nunduly discriminatory or preferential.  We therefore find that we have authority to ensure \nthat tariffs include provisions that clearly and consistently address the study process for \nthe provision of transmission service to Eligible Customers on behalf of large loads, \nincluding the unique impacts that providing transmission service to Eligible Customers \non 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.131  As such, we recognize that states will continue to regulate:  \n(1) the specific terms of retail sales to large load;132 (2) which entities may make retail \nsales within their borders, including which entities are legally permitted to provide \nelectricity to retail large load customers;133 and (3) any siting decisions and construction \nassociated with the large load project.134  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 ISO-NE’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 \n \n131 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th \n1107, 1129 (6th Cir. 2025). \n132 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). \n133 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69. \n134 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":32,"startToken":11957,"endToken":12399,"text":"Docket No. EL26-72-000 \n- 32 - \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 ISO-NE’s Tariff as it relates to \nhow ISO-NE and/or the Participating Transmission Owners will study the provision of \ntransmission service to Eligible Customers on behalf of large loads and explain our \nconcerns that the lack of sufficiently clear and consistent provisions regarding the study \nprocess for the provision of transmission service to Eligible Customers on behalf of large \nloads is unjust and unreasonable or unduly discriminatory or preferential.  We then \nconsider whether the Tariff is unjust and unreasonable without certain elements.  First, \nwe consider whether the Tariff lacks sufficiently clear and consistent Tariff provisions \nestablishing an appropriate definition of large load, as a separate category of load.  \nSecond, we consider whether the Tariff lacks sufficiently clear and consistent Tariff \nprovisions establishing an application process and requirements for Eligible Customers \nrequesting transmission service on behalf of large loads and a study process that \nconsiders the unique operational challenges of providing transmission service to Eligible \nCustomers on behalf of large loads.  Third, we consider whether the Tariff lacks \nsufficiently clear and consistent Tariff provisions establishing ongoing operational \nrequirements necessary to ensure that ISO-NE can reliably provide transmission service \ngiven the unique operational impacts on the transmission system of providing \ntransmission service to Eligible Customers on behalf of large loads.  Finally, we consider \nwhether the Tariff requires such ongoing operational requirements for Eligible Customers \ntaking transmission service on behalf of large loads to be memorialized in service \nagreements. \n \nWe preliminarily find that ISO-NE’s Tariff appears to be unjust and unreasonable \nor unduly discriminatory or preferential because it does not contain provisions addressing \nwith sufficient clarity and consistency how ISO-NE and/or the Participating Transmission \nOwners will study the provision of transmission service to Eligible Customers on behalf \nof large loads.  We recognize that ISO-NE and/or the Participating Transmission Owners \nmay have existing load integration processes, including studies that are performed in \nevaluating the provision of transmission service to Eligible Customers on behalf of large \nloads.135  However, we are concerned that those processes and any required studies with \nregard to the provision of transmission service are not described in the Tariff with the \ndegree of clarity and specificity necessary to ensure that the transmission provider can \nmitigate operational risks of providing transmission service to Eligible Customers on \nbehalf of large loads, given their impact on the transmission system, avoid disputes \nregarding how studies are conducted, deter speculative or duplicative requests for \n \n135 See supra PP 21, 26."},{"page":33,"startToken":12399,"endToken":12805,"text":"Docket No. EL26-72-000 \n- 33 - \ntransmission service by Eligible Customers on behalf of large loads, and help avoid \nexcessive and unnecessary network upgrades.  Moreover, we are concerned that the \nexisting Tariff does not contain other elements akin to those described below, which we \npreliminarily find may be necessary to ensure that the rates, terms, and conditions of \njurisdictional transmission service are just and reasonable.   \n \nAt the outset, we recognize that the Participating Transmission Owners may be \nprimarily responsible for conducting the studies that (1) evaluate whether a large load \nmay be interconnected to the transmission system and served by the Eligible Customer, \nand (2) determine whether network upgrades are necessary to provide transmission \nservice.  This may be particularly true where an Eligible Customer seeks local \ntransmission service on behalf of a large load and where that service takes place over \nnon-PTFs.  We appreciate that this role may stem from how ISO-NE and the \nParticipating Transmission Owners allocated rights and responsibilities in the governing \ndocuments establishing ISO-NE.  We do not seek to alter that allocation of rights and \nresponsibilities.   \n \nWe are nonetheless concerned that ISO-NE’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.136  \nWhile the ISO-NE region has seen a smaller growth in large loads than other regions, \nlarge loads are looking to interconnect in the region.137  ISO-NE itself has recognized that \nlarge loads can be highly uncertain in terms of attrition rates, relative construction time, \nand electric demand characteristics.138  New England Consumer-Owned Systems note \nthat the addition—or sudden loss—of large loads’ demand can reshape regional power \nflows, trigger major transmission and voltage support needs, and impose substantial costs \non existing customers if not properly regulated.139  As a result, providing transmission \nservice to Eligible Customers on behalf of large loads may be more complex and could \n \n136 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-\ncharacteristics-and-risks-of-emerging-large-loads.pdf (NERC Characteristics and Risks \nof Large Loads). \n137 See supra P 8. \n138 ISO-NE Letter at 2. \n139 New England Consumer-Owned Systems November 21 ANOPR Comments at \n2."},{"page":34,"startToken":12805,"endToken":13226,"text":"Docket No. EL26-72-000 \n- 34 - \nraise greater reliability concerns for the transmission system, relative to a situation where \nEligible Customers seek transmission service on behalf of traditional load.   \n \nWe acknowledge that ISO-NE’s Tariff currently outlines study procedures for the \nprovision of Regional Network Service to Eligible Customers.140  However, the study \nprocedures in Tariff Section II.19 refer to the LGIP and SGIP in Schedules 22 and 23, \nwhich explicitly pertain to interconnection customers.141  In addition, Eligible Customers \nseeking Local Transmission Service go through study processes that may be less clear or \nvary depending on which Participating Transmission Owner is providing the Local \nTransmission Service.  Without a clear and consistent process to study the provision of \ntransmission service to Eligible Customers on behalf of large loads, ISO-NE and/or the \nParticipating Transmission Owners may not fully capture the transmission system \nimpacts of providing such transmission service, which could result in significant \noperational risks for the transmission system.  Furthermore, we are concerned that, \nwithout sufficiently clear and consistent Tariff provisions, ISO-NE will not have the \nongoing visibility and operational control necessary to provide reliable transmission \nservice. \n \nWe are also concerned that the absence of sufficiently clear and consistent tariff \nprovisions for how ISO-NE and/or the Participating Transmission Owners will study the \nprovision of transmission service to Eligible Customers on behalf of large loads will lead \nto disputes over a variety of issues—e.g., study timelines and delays,142 how the \ntransmission service needed on behalf of the large load is studied,143 what types of \nnetwork upgrades are considered, and how required network upgrades to provide the \nrequested transmission service are determined.144  Such disputes may arise from the lack \n \n140 See supra PP 21-22. \n141 ISO-NE Tariff, § II.19.2. \n142 See, e.g., CEBA November 21 ANOPR Comments at 12-13; Eolian November \n21 ANOPR Comments at 14-16; Institute for Progress November 21 ANOPR Comments \nat 7-8; Microsoft November 21 ANOPR Comments at 9; ODEC December 5 ANOPR \nComments at 4. \n143 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 \nComments at 3; GridCare December 5 ANOPR Comments at 1-2; L. Lynne Kiesling \nNovember 21 ANOPR Comments at 10. \n144 Specifically, commenters raised concern that transmission providers/owners \nmay only consider traditional transmission infrastructure or that there is a lack of"},{"page":35,"startToken":13226,"endToken":13683,"text":"Docket No. EL26-72-000 \n- 35 - \nof transparency in how studies are performed and how decisions will be made.145  We are \nthus concerned that the lack of clear and consistent provisions in ISO-NE’s Tariff related \nto the study process for the provision of transmission service to Eligible Customers on \nbehalf of large loads appears to be unjust and unreasonable or unduly discriminatory or \npreferential.   \n \nLastly, we are concerned that ISO-NE’s existing Tariff fails to deter speculative or \nduplicative requests for transmission service by Eligible Customers on behalf of large \nloads.  ISO-NE itself has a methodology for derating data centers in its load forecasts due \nto their more speculative nature.146  Many ANOPR comments assert that clear and \nconsistent provisions establishing study timelines and costs, readiness requirements, \nand/or penalties will deter speculative or duplicative requests related to large load \nadditions.147  Commenters explain that speculative requests may bog down and delay the \n \nconsideration of alternative transmission solutions.  See, e.g., ACORE November 21 \nANOPR Comments at 3-4, 6-7; American Terawatt November 21 ANOPR Comments at \n4-5; Calibrant November 21 ANOPR Comments at 1-2, 3; CEBA November 21 ANOPR \nComments at 9-10; Chamber of Commerce November 21 ANOPR Comments at 3; CTC \nGlobal Corporation November 21 ANOPR Comments at 1-3; DCC November 21 \nANOPR Comments at 10-11; GridCARE December 5 ANOPR Comments at 4; Industrial \nCustomers November 21 ANOPR Comments at 27-28; Infrastructure Masons December \n5 ANOPR Comments at 18; Iron Mountain Data Centers, LLC November 21 ANOPR \nComments at 3-4; Land Trust Alliance November 21 ANOPR Comments at 5-6; PIOs \nNovember 21 ANOPR Comments at 22; Southeast PIOs November 21 ANOPR \nComments at 44-45; WATT and Advancing Modern Powerlines November 21 ANOPR \nComments at 5-8. \n145 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. \n146 See, e.g., ISO-NE Large Load Forecast Presentation at 8. \n147 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 at \n12-13; EEI November 21 ANOPR Comments at 20; Fervo November 21 ANOPR \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"},{"page":36,"startToken":13683,"endToken":14086,"text":"Docket No. EL26-72-000 \n- 36 - \nstudy process, wasting time and resources for transmission providers;148 result in \ninaccurate study results or delays for other Eligible Customers seeking transmission \nservice on behalf of load;149 create a substantial risk of cost shifts if the large load \nadditions do not materialize as planned;150 and distort load forecasts.151  Clear and \nconsistent study procedures that include readiness requirements (i.e., meaningful \nmilestones and/or financial commitments) can help ensure that Eligible Customers’ \nrequests for transmission service on behalf of large loads are more viable and more likely \nto materialize as planned, given that they must meet specific milestones and/or pay costs \nto proceed.   \n \nMore specifically, we preliminarily find that ISO-NE’s Tariff appears to be unjust \nand unreasonable because it lacks sufficiently clear and consistent Tariff provisions that \naddress certain aspects of the process to provide transmission service to Eligible \nCustomers on behalf of large loads, including:   \n \nNovember 21 ANOPR Comments at 4. \n148 See, e.g., ATC November 21 ANOPR Comments at 12; Eolian November 21 \nANOPR Comments at 17-18; GridCare December 5 ANOPR Comments at 5; Illinois AG \nNovember 21 ANOPR Comments at 9-10; Institute for Progress November 21 ANOPR \nComments at 9; Ohio FEA November 21 ANOPR Comments at 4; Vistra November 21 \nANOPR Comments at 23. \n149 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 at     \n14-15. \n150 See, e.g., Buckeye November 21 ANOPR Comments at 1-2; Exelon November \n21 ANOPR Comments at 3; Kansas Commission November 21 ANOPR Comments at \n12; NRECA November 21 ANOPR Comments at 9; OCC November 21 ANOPR \nComments at 9; Southeast PIOs November 21 ANOPR Comments at 20; State Entities \nNovember 21 ANOPR Comments at 7-8; TAPS November 21 ANOPR Comments at 15, \n22-24; Tri-State November 21 ANOPR Comments at 6, 8; Vistra November 21 ANOPR \nComments at 23. \n151 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 at \n5; Southeast PIOs November 21 ANOPR Comments at 41; Talen November 21 ANOPR \nComments at 9."},{"page":37,"startToken":14086,"endToken":14492,"text":"Docket No. EL26-72-000 \n- 37 - \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 customers152 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 ISO-NE’s Tariff appears to be unjust and \nunreasonable because it lacks a definition of large load, as a new category of load.  \nIntegrating large loads poses specific challenges to transmission system operation given \ntheir size, operational behavior, and unique potential to impact the transmission \nsystem.153  An appropriate definition, including a load size and interconnection voltage \nthreshold, should be based on the characteristics of ISO-NE’s transmission system.  That \nsaid, based on the record in the ANOPR proceeding,154 it appears that it would be \n \n152 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.  \n153 See generally NERC, 2024 Long- Term Reliability Assessment 38 (Dec. 2024, \nupdated July 2025), https://www.nerc.com/pa/RAPA/ra/Reliability%20\nAssessments%20DL/NERC_Long%20Term%20Reliability%20Assessment_2024.pdf). \n154 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); National Grid November 21 ANOPR Comments at 11-12 \n(asserting appropriate thresholds of 50 or 80 MW depending on the region); Nebraska \nBoard November 21 ANOPR Comments at 4 (proposing a 50 MW threshold); New \nMexico Commission November 21 ANOPR Comments at 5 (proposing a 50 MW \nthreshold)."},{"page":38,"startToken":14492,"endToken":14983,"text":"Docket No. EL26-72-000 \n- 38 - \nreasonable to define a large load as a new, commercial or industrial customer, located at a \nsingle site behind one or more points of interconnection, and that has a peak load of 50 \nMW or greater, interconnects to the transmission system at a voltage level of greater than \n69 kV, and is not part of a co-location arrangement.  In its response to this order, ISO-NE \nshould explain whether the Tariff remains just and reasonable without such a definition, \nor propose Tariff revisions establishing its own definition of large load. \n \nSecond, we preliminarily find that ISO-NE’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 ISO-NE \nand/or the Participating Transmission Owners evaluate the provision of transmission \nservice to Eligible Customers on behalf of large loads.  For example, we are concerned \nwith the lack of clarity as to what aspects of the study and provision of Regional Network \nService apply only to interconnection customers subject to the LGIP or SGIP as opposed \nto all Eligible Customers seeking Regional Network Service, as well as with the clarity \nand consistency of the Local Transmission Service study procedures in various \nParticipating Transmission Owners’ Schedule 21 procedures.  ISO-NE’s should explain \nwhether the Tariff remains just and reasonable, for example, without: (1) an application \nprocess that accepts Eligible Customers’ applications for transmission service on behalf \nof large loads on a rolling basis; (2) a non-refundable application fee and sufficient \nreadiness requirements that escalate at distinct phases of the study process to deter \nduplicative or speculative requests for transmission service (e.g., meaningful milestones \nand/or financial commitments); and (3) information and data requirements that Eligible \nCustomers must submit to ISO-NE and/or the Participating Transmission Owners \nregarding the characteristics of the large load on behalf of which the Eligible Customer is \ntaking transmission service, including disclosure to ISO-NE of any substantially similar \npending transmission service requests on behalf of the same large load customer.155  \nISO-NE may also elect to propose Tariff revisions establishing such an application \nprocess, fee, and requirements.   \n \nFurther, ISO-NE’s Tariff appears to lack sufficiently clear and consistent \nprovisions establishing a study process for evaluating the provision of transmission \nservice to Eligible Customers on behalf of large loads that considers the unique \ncharacteristics and impacts of large loads on the transmission system.  For example, we \nare concerned that ISO-NE’s Tariff may not clearly and consistently require ISO-NE or \nthe Participating Transmission Owners to conduct studies that evaluate the transmission \nsystem’s ability to withstand risks observed from analyzed large load behavior created by \nthe large load at the point of interconnection, or any other necessary supplemental studies \n \n155 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)."},{"page":39,"startToken":14983,"endToken":15386,"text":"Docket No. EL26-72-000 \n- 39 - \nto evaluate the impact of providing transmission service to Eligible Customers on behalf \nof large loads.156  Additionally, we preliminarily find that ISO-NE’s Tariff appears unjust \nand unreasonable because it lacks appropriate provisions recognizing within the \ntransmission service request study process the unique operational characteristics of large \nloads that are willing and able to limit their energy withdrawals under certain conditions, \nwhich may thereby lessen or potentially avoid the need for certain network upgrades.  \nWhile flexible large loads can reduce the demand on the transmission system, and \ntherefore potentially reduce the need for additional transmission capacity, additional \ninformational and study requirements may be necessary to account for the dynamic \nnature of these types of loads while maintaining reliability.157  Additionally, we note that \naccurate models using Electromagnetic Transient studies may help to ensure that \ntransmission service needed on behalf of large loads can be provided without \ncompromising reliability.158   \n \nAdditionally, we preliminarily find that ISO-NE’s Tariff appears to be unjust and \nunreasonable because it lacks clear and consistent provisions requiring the evaluation of \nalternative transmission technologies159 as potential solutions to accommodate an \n \n156 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-\nloads.pdf (finding that unique operational characteristics of large loads necessitate \nenhancements to studies). \n157 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. \n158 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.  We acknowledge that Electromagnetic Transient \nstudy processes are already within the scope of the Cluster Study process through which \nRegional Network Service requests are processed.  See supra P 22.  However, we note \nthat it is unclear if such Electromagnetic Transient study processes are carried out under \nLocal Transmission Service studies processes. \n159 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,"},{"page":40,"startToken":15386,"endToken":15796,"text":"Docket No. EL26-72-000 \n- 40 - \nEligible Customer’s request for transmission service on behalf of a large load.  \nAlternative transmission technologies can add more capacity on existing transmission \nlines quickly, often within one to three years.160  Unlike with traditional load growth,161 \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.162  The Commission has previously recognized that alternative transmission \n \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). \n160 WATT and Advancing Modern Powerlines November 21 ANOPR Comments \nat 5-6. \n161 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.”). \n162 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 (Mar. \n2026), 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":41,"startToken":15796,"endToken":16251,"text":"Docket No. EL26-72-000 \n- 41 - \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 \nunjust and unreasonable.163  Further, to the extent network upgrades 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 upgrades 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 \nISO-NE 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 \n163 Improvements to Generator Interconnection Procs. & Agreements, Order No. \n2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), order \non reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ 61,134 \n(2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & Cost \nAllocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order No. \n1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC         \n¶ 61,026 (2025)."},{"page":42,"startToken":16251,"endToken":16718,"text":"Docket No. EL26-72-000 \n- 42 - \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 \ncomplete.164  To the extent ISO-NE or the Participating Transmission Owners already \nhave such procedures and conduct such studies, but those processes are not included in \nthe Tariff, ISO-NE and the Participating Transmission Owners should explain their \nexisting processes and consider whether amendments are necessary to the Tariff to \nmemorialize those processes and also address the concerns expressed herein.  Otherwise, \nISO-NE should explain whether the Tariff remains just and reasonable without:  (1) \nsufficiently clear and consistent provisions to evaluate the impact of providing the \nrequested transmission service to Eligible Customers on behalf of large loads, including \nidentifying the Direct Assignment Facilities and network upgrades necessary to provide \nsuch service reliably; (2) provisions to appropriately recognize within the transmission \nservice study process the unique operational characteristics of large loads; (3) a study \ndeadline of no more than 60-90 calendar days; or propose Tariff revisions establishing \nthem \n \nThird, we preliminarily find that ISO-NE’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.165  For example, we are concerned that ISO-NE’s Tariff does not require \ntransmission customers to provide ISO-NE hourly forecasts, telemetry data, and other \n \n164 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.  \n165 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":43,"startToken":16718,"endToken":17176,"text":"Docket No. EL26-72-000 \n- 43 - \ndata to ensure sufficient visibility or specify requirements for maintaining communication \nchannels between ISO-NE and the transmission customer on behalf of the large load.  \nAdditionally, we are concerned that the Tariff does not require transmission owners to \ninstall, and transmission customers to pay for, equipment to enable ISO-NE to monitor \nlarge loads for impacts of, for example, fast-ramping load that may impact the \ntransmission system too quickly to be captured by conventional data acquisition systems \n(e.g., the need for phasor measurement units or similar equipment).  We are also \nconcerned that the Tariff does not require the transmission customer to enable ISO-NE to \nremotely disconnect large loads when necessary to maintain reliability of the \ntransmission system, with the costs of such equipment directly assigned to the \ntransmission customer, as well as the terms and conditions under which ISO-NE may \nremotely disconnect the large load (e.g., emergency conditions, so that transmission \nequipment is not harmed).  Further, we are concerned that the Tariff does not specify \nramp rate or ride-through requirements with which the transmission customer taking \ntransmission service on behalf of the large load must comply.  Lastly, we are concerned \nthat the Tariff does not specify requirements for necessary control technologies and/or \nprotection systems that may be necessary to limit a transmission customer’s withdrawals \nfrom the transmission system as appropriate.166  ISO-NE should explain whether the \nTariff remains just and reasonable without these or other ongoing operational \nrequirements as part of the rates, terms, and conditions of transmission service or propose \nTariff revisions establishing necessary ongoing operational requirements. \n \nFourth, we preliminarily find that ISO-NE’s Tariff appears to be unjust and \nunreasonable because it lacks pro forma provisions in a transmission service agreement \nbetween ISO-NE and the transmission customer taking transmission service on behalf of \na large load to memorialize the above terms (e.g., equipment requirements, data \nrequirements, remote disconnect capability).167  We are concerned that, without such   \npro forma provisions in a transmission service agreement between ISO-NE and the \ntransmission customer, ISO-NE may be unable to enforce ongoing operational \nrequirements for transmission customers taking transmission service on behalf of large \n \n166 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 PP 99, \n103. \n167 We recognize that an Eligible Customer must be party to a Market Participant \nService Agreement or Service Agreement for Regional Network Service prior to \ninitiating Regional Network Service, and must be party to a Local Service Agreement \nprior to initiating Local Transmission Service.  However, we find that these agreements \ndo not contain provisions that memorialize the terms described above.  See supra PP 21, \n26."},{"page":44,"startToken":17176,"endToken":17630,"text":"Docket No. EL26-72-000 \n- 44 - \nloads.  ISO-NE should explain whether the Tariff remains just and reasonable without \nsuch pro forma provisions in a transmission service agreement, or propose revisions to \ninclude pro forma provisions memorializing the ongoing operational requirements in a \ntransmission service agreement between ISO-NE and the transmission customer.  \nB. \nCost Shifting Risk Among Transmission Customers \n \nWe next preliminarily find that ISO-NE’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 (1) \ntransparency regarding the assignment of network upgrades, and their associated costs, \nthat are needed to provide transmission service to Eligible Customers on behalf of large \nloads; and (2) a pro forma cost recovery agreement between ISO-NE, the relevant \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 ISO-NE and the Participating Transmission Owners, to the extent the \nmatters addressed herein implicate aspects of the Tariff over which they have the filing \nrights, to explain whether the Tariff remains just and reasonable without (1) robust, \naccurate, and systematic provision of data on ISO-NE’s website in a single location, and \nin an easily accessible format that is searchable and allows users to filter the data, \nregarding the cost for network upgrades needed to provide transmission service to \nEligible Customers on behalf of large loads; and (2) a pro forma cost recovery agreement \nbetween ISO-NE, the relevant transmission owner, and the Eligible Customer taking \ntransmission service on behalf of a large load, or to propose Tariff revisions to provide \nadditional transparency and establish such a pro forma cost recovery agreement.  We \nencourage state regulators responsible for setting retail rates to provide input to ISO-NE \nregarding their transparency needs.   \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 to \nEligible Customers on behalf of large loads are inputs to jurisdictional transmission rates,"},{"page":45,"startToken":17630,"endToken":18054,"text":"Docket No. EL26-72-000 \n- 45 - \nand 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 \ntransmission system.168  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.169  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.170  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,171 as well as voluntary efforts by transmission owners to protect \nretail ratepayers through cost recovery agreements with large loads.172  We are also \nencouraged by the execution of the President’s Ratepayer Protection Pledge, through \n \n168 See, e.g., National Grid November 21 ANOPR Comments at 16-17; New \nEngland Consumer-Owned Systems November 21 ANOPR Comments at 4, 19-21; New \nEngland Public Systems November 21 ANOPR Comments at 9-10. \n169 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. \n170 Id. P 68. \n171 See, e.g., EEI March 12 ANOPR Comments at Attach. 1, 9-13; NARUC    \nApril 13 ANOPR Comments at 2-6 (noting examples of states acting to address large \nload interconnection).  \n172 See, e.g., Commonwealth Edison Co. 194 FERC ¶ 61,106 (2026); \nCommonwealth Edison Co., 194 FERC ¶ 61,109 (2026); Commonwealth Edison Co.,   \n194 FERC ¶ 61,110 (2026); Commonwealth Edison Co., 194 FERC ¶ 61,113 (2026); \nPECO Energy Co., 193 FERC ¶ 61,148 (2025); Dayton Power & Light Co., 192 FERC    \n¶ 61,103 (2025); Dayton Power & Light Co., 189 FERC ¶ 61,220 (2024)."},{"page":46,"startToken":18054,"endToken":18481,"text":"Docket No. EL26-72-000 \n- 46 - \nwhich data center developers have committed to shield retail ratepayers from increased \nelectricity prices.173   \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 \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 ISO-NE’s Tariff appears to be unjust and unreasonable \nor unduly discriminatory or preferential because it does not contain provisions requiring \nthe provision of data on ISO-NE’s website in a single location, and in an easily accessible \nformat that is searchable and allows users to filter the data, on transmission service \nrequested by Eligible Customers on behalf of large loads, for network upgrades evaluated \nin the local transmission planning process that are needed to provide transmission service \nto Eligible Customers on behalf of those large loads, and the costs for those network \nupgrades.  We preliminarily find that cost transparency measures are needed to provide \nstakeholders with sufficient information and visibility regarding the network upgrades, \nand their associated costs, needed to provide transmission service to Eligible Customers \non behalf of large loads.   \n \nWe recognize that there may have been limited large load growth in the ISO-NE \nregion so far; however, the record indicates the potential for large load growth in the \nregion and transmission owners are studying the need for network upgrades that will be \nneeded to provide transmission service to Eligible Customers on behalf of large loads.174  \nISO-NE also included a forecast for large loads embedded in its 2026 CELT load \n \n173 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026). \n174 See supra P 8."},{"page":47,"startToken":18481,"endToken":18963,"text":"Docket No. EL26-72-000 \n- 47 - \nforecast.175  ISO-NE’s Tariff does not appear to require that information identifying the \nnetwork upgrades needed to provide transmission service to Eligible Customers on behalf \nof large loads and the costs of those network upgrades determined through local \ntransmission planning processes be readily available on ISO-NE’s website in a single \nlocation, and in an easily accessible format that is searchable and allows users to filter the \ndata.  The speed and scale with which Eligible Customers are seeking transmission \nservice on behalf of large loads makes it difficult for interested parties, including \ntransmission customers and state regulators, to accurately assess which transmission costs \nare driven by requests for transmission service by Eligible Customers to serve large \nloads.  We are concerned that the potentially speculative nature of requests for \ntransmission service by Eligible Customers on behalf of large loads,176 the speed and \nscale with which large loads might seek to be added to the transmission system, the \npotential need for significant network upgrades to provide transmission service to \nEligible Customers on behalf of large loads, and the lack of centralized information on \nthe associated transmission costs in ISO-NE hamper the ability of the Commission and \nstakeholders (including transmission customers and state regulators177) to understand and \naccurately assess the relationship between the addition of large loads to the transmission \nsystem and wholesale transmission costs.   \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 process178 that are needed \n \n175 See ISO-NE Large Load Forecast Presentation at 14.  \n176 See supra P 54. \n177 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.”).   \n178 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"},{"page":48,"startToken":18963,"endToken":19426,"text":"Docket No. EL26-72-000 \n- 48 - \nto provide transmission service to Eligible Customers on behalf of large loads, ISO-NE \nmust 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.179        \n \nAccordingly, we preliminarily find that ISO-NE’s Tariff appears to be unjust and \nunreasonable because it does not require the provision of data on ISO-NE’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 \n \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. \n179 See OCC November 21 ANOPR Comments at 3 (“Consumers, state advocates \nand state regulatory commissions have a right to know which entities are seeking large-\nload interconnections, the nature of the requested service, and how related costs could \nflow through to transmission and distribution rates.”); U.S. House of Representatives \nCommittee on Energy and Commerce Ranking Members November 21 ANOPR \nComments at 2 (urging the Commission to “require sufficient transparency from grid \noperators so it can determine which specific large load facilities are responsible for grid \nupgrade needs”); CPUC November 21 ANOPR Comments at 16-17 (asserting that the \npublic posting of large load cost responsibility determinations would improve \ntransparency, to the benefit of businesses and ratepayers)."},{"page":49,"startToken":19426,"endToken":19889,"text":"Docket No. EL26-72-000 \n- 49 - \nrequests for transmission service by Eligible Customers on behalf of large loads, and the \ncosts of those network upgrades.  ISO-NE should explain whether the Tariff remains just \nand reasonable without provisions that would require ISO-NE and the Participating \nTransmission Owners to publicly post and regularly update data that details:  (1) the \naggregate amounts of proposed large load additions in ISO-NE’s footprint, including the \naggregate amounts in each transmission pricing zone; (2) the planned network upgrades \nneeded to provide transmission service to Eligible Customers on behalf of large loads, \nidentified by type of equipment and network upgrades (e.g., new substation, \nreconductoring, a new high-voltage transmission line) for each transmission service \nrequest; and (3) cost estimates for those network upgrades; or propose such Tariff \nrevisions.  ISO-NE and the Participating Transmission Owners should also consider what \nother data related to transmission costs resulting from the provision of transmission \nservice to Eligible Customers on behalf of large loads would be useful to include on \nISO-NE’s website.  To the extent there are concerns about data confidentiality, ISO-NE \nand the Participating Transmission Owners should consider whether there are ways to \nmitigate those concerns while still providing the necessary transparency. \n3. \nCost Recovery Agreements \n \nWe next preliminarily find that ISO-NE’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 pro \nforma cost recovery agreement between ISO-NE, 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.180  Commenters also argue that retail-level large load tariffs do not \nprotect wholesale transmission customers from cost shifting.181  Specifically, commenters \n \n180 See, e.g., Buckeye November 21 ANOPR Comments at 8-13; APPA November \n21 ANOPR Comments at 6 (“Wholesale transmission customers in particular could be \nleft shouldering massive costs if new large loads do not ultimately attain or maintain the \nlevel of electricity demand that is being forecasted.”); NRECA November 21 ANOPR \nComments at 21 (noting the risk that other transmission customers could bear stranded \nupgrade costs caused by large loads that they cannot absorb); TAPS November 21 \nANOPR Comments at 22-24; California DWR November 21 ANOPR Comments at 8. \n181 TAPS November 21 ANOPR Comments at 26 (“[A] number of state \ncommissions are moving forward with retail large load tariffs, which provide for varying"},{"page":50,"startToken":19889,"endToken":20309,"text":"Docket No. EL26-72-000 \n- 50 - \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.182  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.”183  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.184  New \nEngland Consumer-Owned Systems also assert that where costs arise solely from the \naddition of new loads, shifting those costs to existing ratepayers would effectively require \nratepayers to subsidize new entrants.185 \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 \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 \n \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. \n182 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 \nANOPR Comments at 26-27 & nn.50-51.  \n183 Kansas Commission November 21 ANOPR Comments at 11-12.  \n184 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 Commission-\njurisdictional transmission revenue requirement so that other customers are protected,” in \na Construction Service Agreement with Amazon). \n185 New England Consumer-Owned Systems November 21 ANOPR Comments at \n4, 19-20."},{"page":51,"startToken":20309,"endToken":20775,"text":"Docket No. EL26-72-000 \n- 51 - \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 \nISO-NE’s Tariff does not require cost recovery agreements between ISO-NE, the \nrelevant transmission owner, and the Eligible Customer taking transmission service on \nbehalf of a large load.  Such agreements would help ensure that the Eligible Customer \nmakes a minimum contribution to the transmission owner’s transmission revenue \nrequirement commensurate with the costs incurred to provide the requested transmission \nservice, including 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 \nISO-NE, the relevant transmission owner, and the Eligible Customer taking transmission \nservice on behalf of a large load to enter into a cost recovery agreement that requires the \nEligible Customer to make a minimum contribution toward the transmission owner’s \ntransmission revenue requirement, if the Eligible Customer ultimately takes less \ntransmission service than anticipated because the large load does not materialize as \nplanned or is not developed at all.  We preliminarily find that such cost recovery \nagreements are necessary to help ensure that the Eligible Customer is responsible for \ntimely paying the costs of large load-driven transmission (i.e., the costs incurred to \nprovide them with the requested transmission service, including the costs of any needed \nnetwork upgrades), rather than having those costs paid by other transmission customers \nthat neither caused the need for nor benefit commensurately from those network \nupgrades.186  Our preliminary finding is not intended to alter or call into question existing \nregional cost allocation methods for network upgrades, but instead is focused on helping \nto prevent cost shifting among transmission 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 \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 \n \n186 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":52,"startToken":20775,"endToken":21248,"text":"Docket No. EL26-72-000 \n- 52 - \nrequirement.187  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 Commission-\njurisdictional transmission revenue requirement, we find that such an agreement should \nbe filed with the Commission.188  To reduce duplicative credit requirements and \ntransaction costs, we direct further briefing on whether it would be appropriate for such \nan agreement to substitute for the requirement on the Eligible Customer to enter into a \ncost recovery agreement with the transmission owner, if the agreement with the large \nload customer provided comparable or greater protection against cost shifting among \ntransmission customers than an agreement between the transmission owner and the \nEligible Customer would.   \n \nIn addition to our preliminary finding that ISO-NE’s Tariff is unjust and \nunreasonable because it lacks a pro forma cost recovery agreement of this type, we also \npreliminarily find that the minimum contribution required pursuant to such an agreement \nshould be based on the level of jurisdictional transmission service (in MW) requested by \nthe Eligible Customer on behalf of the large load.  That figure is in turn tied to how \nISO-NE and/or Participating Transmission Owners will study the requested transmission \nservice and determine any necessary network upgrades that must be developed to provide \nthe requested transmission service.  We note, however, that there may be other just and \nreasonable methods for determining this minimum contribution, including methods that \naccount for potential timing differences between when costs are incurred to develop \nneeded Network Upgrades and the pace at which the large load ramps toward energizing \nat its full level of requested service.  We further preliminarily find that the cost recovery \nagreement should include a credit support (or other financial security) requirement \nsufficient to secure the obligations of the Eligible Customer taking transmission service \non behalf of a large load to pay the amounts owed pursuant to the cost recovery \nagreement.  We find that a cost recovery agreement with a specified minimum financial \ncontribution and financial security sufficient to secure such contribution is necessary to \nmitigate cost shifting if the Eligible Customer ultimately takes less transmission service \nthan anticipated because the large load does not materialize as planned or is not \n \n187 See supra note 172. \n188 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":53,"startToken":21248,"endToken":21684,"text":"Docket No. EL26-72-000 \n- 53 - \ndeveloped at all.  We preliminarily find that an Eligible Customer may include a credit \nsupport or other financial security posted by a large load as part of a retail agreement to \navoid creating duplicative credit support requirements.  ISO-NE should explain why such \na pro forma cost recovery agreement is not necessary to ensure just and reasonable rates, \nor propose such a pro forma cost recovery agreement.  To the extent that stakeholders \nbelieve that other mechanisms could address our cost shifting concerns, we seek further \nbriefing as discussed below.189 \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.190  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. \n \nAlthough the Commission’s concerns surrounding cost shifting described above \nmay not present the same as in other RTOs/ISOs, we remain concerned that cost shifting \nmay occur.  We acknowledge that the requests for Regional Network Service by Eligible \nCustomers on behalf of large loads may be studied in a Cluster Study.  We note that the \nCluster Study may result in network upgrades or new facilities that the Eligible Customer \nrequesting Regional Network Service on behalf of the large load is obligated to pay for, \nincluding applicable study costs consistent with Commission policy and Schedules 11 \nand 12.191  However, we note that these cost allocation provisions in Schedules 11 and 12 \nmay not be sufficiently clear as they do not specifically contemplate network upgrades or \nfacilities identified for the provision of Regional Network Service.  We also remain \nconcerned that cost shifting may occur through the recovery of the Participating \nTransmission Owners’ transmission revenue requirements for transmission projects \nplanned through the Local Transmission Planning Process due to speculative requests to \naccommodate transmission service to serve large loads, i.e., where large loads do not \nmaterialize or where the MW quantity of such large loads is lower than proposed, or \nbecause of the study process used to evaluate the facilities needed, and the associated \ncosts, to accommodate the provision of transmission service to Eligible Customers on \nbehalf of large loads. \n \n189 See infra P 122.  \n190 See 18 C.F.R. pt. 101 (2025). \n191 ISO-NE Tariff, § II.21.1."},{"page":54,"startToken":21684,"endToken":22057,"text":"Docket No. EL26-72-000 \n- 54 - \nC. \nCo-Location Arrangements and Load with Behind the Meter \nGeneration \n \nThe Commission recently addressed in the PJM region the need for sufficiently \nclear and consistent tariff provisions addressing the rates, terms, and conditions that apply \nto co-location arrangements and for transmission services that reflect an Eligible \nCustomer taking transmission service on behalf of Eligible Load192 that is willing and \nable to limit its energy withdrawals from the transmission system under certain \nconditions.193  As discussed below, ISO-NE’s Tariff appears to be unjust and \nunreasonable because it lacks such provisions.   \n \nWe direct ISO-NE and the Participating Transmission Owners, to the extent the \nmatters addressed herein implicate aspects of the Tariff over which they have the filing \nrights, to explain whether the Tariff remains just and reasonable without provisions \naddressing the rates, terms and conditions that apply to interconnection customers serving \nco-located load and for Eligible Customers taking transmission service on behalf of \nEligible Load, or propose Tariff revisions establishing the rates, terms, and conditions \nthat apply to co-location arrangements.   \n1. \nDefinition \n \nThe PJM Co-Location Order adopted the following definition of co-located load:  \na “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 to the PJM Transmission System.”194  The PJM     \nCo-Location Order used the term co-location arrangement when referring to both the co-\nlocated load and the associated generator.195   \n \nFor purposes of this order, it appears that it would be reasonable to define co-\nlocated load as a configuration that refers to end-use customer load that is physically \nconnected to the facilities of an existing or planned generating facility on the generator \ninterconnection customer’s side of the point of interconnection to the RTO/ISO’s \n \n192 As discussed below, for purposes of this order, we will use the term Eligible \nLoad to refer to co-located load and/or load with behind the meter generation.  See infra \nP 88. \n193 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 2; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at PP 91-102. \n194 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164 (alterations in original). \n195 Id. P 3."},{"page":55,"startToken":22057,"endToken":22404,"text":"Docket No. EL26-72-000 \n- 55 - \ntransmission system.  In this order, we will also use the term co-location arrangement \nwhen referring to both the co-located load and the associated generating facility. \n \nISO-NE’s Tariff does not define the term “Behind the Meter Generation.”  For \npurposes of this order, it appears reasonable based upon the record to refer to Behind the \nMeter Generation (BTMG) similarly to how that term is used in the PJM Co-Location \nOrder, as a generating facility that delivers energy to load without using the transmission \nsystem or any distribution facilities.196 \n \nFor purposes of this order, we will use the term Eligible Load to refer to co-\nlocated load and/or load with BTMG.197 \n2. \nJurisdiction \n \nAs explained in the PJM Co-Location Order, the Commission has exclusive \njurisdiction to oversee the interconnection of generating facilities to the interstate \ntransmission system, including where generators serve co-located load.198  The \nCommission retains exclusive authority to regulate the procedures and agreements that \napply to the interconnection of a generator that will make wholesale sales, both where the \ngenerator interconnects directly to the interstate transmission system and where a \ngenerator interconnects to dual-use distribution facilities.199  Further, the Commission has \nexclusive jurisdiction over the provision of transmission service to an Eligible Customer \non behalf of Eligible Load, provided that transmission of electricity is in interstate \ncommerce.200  As the Commission found in the PJM Co-Location Order, we continue to \nacknowledge that the application of these principles depends on the specific facts and \ncircumstances presented in particular situations.201   \n \n196 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 7 n.19 (citing PJM, \nIntra-PJM Tariffs, OATT, § I.1 (Definitions - A-B) (21.0.0)). \n197 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91. \n198 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171 (citing 16 U.S.C.         \n§§ 824d, 824e; EPSA, 577 U.S. at 278). \n199 Id. P 172 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, \n1282 (D.C. Cir. 2007)). \n200 Id. P 173. \n201 Id. P 174."},{"page":56,"startToken":22404,"endToken":22831,"text":"Docket No. EL26-72-000 \n- 56 - \n \nAdditionally, we reiterate that certain other aspects of co-location arrangements \nfall squarely within the jurisdiction of the states.  As we explained in the PJM Co-\nLocation Order, states retain exclusive authority over the specific terms of retail sales and \nretail rate design, including retail cost allocation to the co-located load; which entities are \nlegally permitted to provide electricity to retail customers in co-location arrangements; \nand which generating facilities are sited and allowed to serve co-located load.202 \n3. \nTariff Provisions \n \nWe preliminarily find that ISO-NE’s Tariff appears to be unjust and unreasonable \nor unduly discriminatory or preferential because it does not contain provisions addressing \nwith sufficient clarity and consistency the rates, terms, and conditions of service that \napply to interconnection customers serving co-located load.  We also preliminarily find \nthat ISO-NE’s Tariff appears to be unjust and unreasonable or unduly discriminatory or \npreferential because it does not contain provisions addressing with sufficient clarity and \nconsistency transmission services that reflect that an Eligible Customer taking \ntransmission service on behalf of Eligible Load is willing and able to limit its energy \nwithdrawals from the transmission system under certain conditions.   \n \nThe absence of such provisions may leave entities unable to determine what steps \nthey can or must take to effectuate co-location arrangements of various configurations.  \nOne step includes determining how interconnection customers serving co-located load \nmay use generator interconnection processes in ISO-NE’s Tariff to facilitate their co-\nlocation arrangements.  A further step includes requiring interconnection customers \nserving co-located load to specify the Eligible Customer taking transmission service on \nbehalf of the co-located load under the Tariff for purposes of assessing charges, including \nthe appropriate charges for wholesale services that should apply to such Eligible \nCustomers.  Without such a common and consistent understanding of entities’ \nresponsibilities relevant to co-location arrangements, many of which may significantly \naffect rates and are realistically susceptible of specification,203 we are concerned that \nthese arrangements may be developed in a manner that is itself unjust and unreasonable \nor that may result in unjust and unreasonable rates for other customers.   \n \nMoreover, as discussed further below, we are especially concerned that the \nabsence of Tariff provisions addressing transmission and ancillary service rates for \nEligible Customers taking transmission service on behalf of Eligible Load creates the \npotential that Eligible Customers, on behalf of Eligible Load, may not be required to pay \nfor wholesale transmission services that they receive, as required by the cost causation \n \n202 Id. PP 167-169. \n203 Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th 1307, 1312 (D.C. Cir. \n2023)."},{"page":57,"startToken":22831,"endToken":23277,"text":"Docket No. EL26-72-000 \n- 57 - \nprinciple.  That principle provides that all Commission-jurisdictional rates and charges \nmust “reflect to some degree the costs actually caused by the customer who must pay for \nthem,”204 and that costs must be allocated in a manner that is at least roughly \ncommensurate with the benefits that entity receives.205 \n \nWe preliminarily find that ISO-NE’s Tariff appears to be unjust and unreasonable \nbecause it lacks sufficient clarity and consistency as to the rates, terms, and conditions of \nservice that apply to interconnection customers serving co-located load, including the \nscope of the analyses ISO-NE performs as part of its existing study process to evaluate \nthe impacts of co-location arrangements, which may need to account for any potential \ndynamic impacts of co-located load and any potential impacts of requests to modify an \nexisting generating facility’s interconnection service level to serve co-located load on \ntransmission system reliability.  Additionally, in the PJM Co-Location Order, the \nCommission found that it was necessary to clarify that interconnection customers seeking \nto use new generating facilities to serve co-located load may (1) request interconnection \nservice at a level below the generating facility’s maximum facility output; (2) use \nexisting procedures to accelerate interconnection requests that satisfy certain tariff \ncriteria; and (3) request provisional interconnection service and surplus interconnection \nservice.206  As such, interconnection customers seeking to use their generating facilities \nto serve co-located load have no means of knowing the appropriate mechanism for setting \nforth the terms and conditions of co-location arrangements.  We are concerned that the \ndetails of such a process—including the existing rules and studies applicable to such \ngenerator interconnection arrangements—are not sufficiently detailed in the Tariff to \nensure clarity for how interconnection customers may seek to serve co-located load.  \nMoreover, without an Eligible Customer designated to take transmission service on \nbehalf of a co-located load, there is no mechanism for ISO-NE to address situations in \nwhich a co-located load withdraws energy from the transmission system. \n \nTherefore, we preliminarily find that ISO-NE’s Tariff appears to be unjust and \nunreasonable because it does not contain provisions addressing with sufficient clarity and \nconsistency the rates, terms, and conditions of service that apply to interconnection \ncustomers serving co-located load.  ISO-NE should explain whether the Tariff remains \njust and reasonable without such provisions, or propose Tariff revisions. \n \n204 Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368. \n205 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d at 476. \n206 PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 231-235.  PJM’s \ncompliance filing proposing revisions in response to these directives was accepted in part \non April 16, 2026.  PJM Interconnection, L.L.C., 195 FERC ¶ 61,030."},{"page":58,"startToken":23277,"endToken":23708,"text":"Docket No. EL26-72-000 \n- 58 - \n \nWe have similar concerns regarding ISO-NE’s existing rate designs for \ntransmission and ancillary services that are used by Eligible Customers taking \ntransmission service on behalf of Eligible Load.  The Commission has previously found \nthat co-located loads that are synchronized with the transmission system use and benefit \nfrom at least some ancillary services and may be reasonably charged for such benefits. 207  \nSpecifically, the Commission has found that, regardless of whether a co-located load \nwithdraws energy from the transmission system, co-located load relies on and benefits \nfrom regulation service and black start service, and concluded that Eligible Customers \ntaking one of the new transmission services (discussed below) on behalf of co-located \nload must pay for these ancillary services on a gross demand basis.208  In the PJM        \nCo-Location Rehearing Order, the Commission applied these findings to Eligible \nCustomers taking transmission service on behalf of load with BTMG.209  However, ISO-\nNE’s Tariff does not appear to include a mechanism by which an Eligible Customer, on \nbehalf of Eligible Load, would be charged for ancillary services commensurate with its \nusage of such services, particularly if such customer did not withdraw energy from the \ntransmission system.  We note that New England Consumer-Owned Systems asserts that \nco-location arrangements could allow large loads to bypass transmission, energy, \ncapacity, and ancillary service charges while shifting those costs to regional transmission \ncustomers.210 \n \nTherefore, we preliminarily find that ISO-NE’s Tariff appears to be unjust and \nunreasonable because it does not address whether and how Eligible Customers taking one \nof the new transmission services on behalf of Eligible Loads will be charged for their use \nof regulation and black start services, which introduces the risk that Eligible Load may \nbenefit from regulation and black start services without contributing to cost recovery for \nsuch services.  As noted in the PJM Co-Location Order, this introduces the risk that costs \nmay be allocated entirely to other transmission customers and passed through to \nresidential customers, among others.211  ISO-NE should explain whether the Tariff \nremains just and reasonable without requiring Eligible Customers taking one of the new \ntransmission services on behalf of Eligible Loads to pay for regulation and black start \nservices on a gross demand basis, or propose Tariff revisions that require them to do so. \n \n207 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 183. \n208 Id. PP 184-185. \n209 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 400. \n210 New England Consumer-Owned Systems November 21 ANOPR Comments at \n3, 13-16. \n211 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 159."},{"page":59,"startToken":23708,"endToken":24166,"text":"Docket No. EL26-72-000 \n- 59 - \n \nThe Commission also found in the PJM Co-Location Order that Eligible \nCustomers taking transmission service on behalf of co-located loads are willing and able \nto limit their energy withdrawals from the transmission system under certain conditions.  \nAs such, the Commission found that Eligible Customers taking transmission service on \nbehalf of co-located loads should be allowed to choose a transmission service that aligns \nwith their use of the transmission system and therefore aligns the charges for service with \nthe benefits received.212  On rehearing, the Commission found that it is just and \nreasonable for these services to be available to Eligible Customers taking transmission \nservice on behalf of loads with BTMG.213  We are concerned that ISO-NE’s Tariff lacks \ntransmission services that would reflect the ability of Eligible Customers on behalf of \nEligible Loads to take transmission services that align with their use of the transmission \nsystem, which may result in inefficient and costly transmission buildout and costs paid by \ntransmission customers.214   \n \nTherefore, we also preliminarily find that ISO-NE’s Tariff appears to be unjust \nand unreasonable because it does not include transmission services that reflect Eligible \nCustomers taking transmission service on behalf of Eligible Load that are willing and \nable to limit their use of the transmission system under certain conditions.  ISO-NE \nshould explain whether the Tariff remains just and reasonable without the transmission \nservices described by the Commission in the PJM Co-Location Order, with regional \nvariation as appropriate, being available to Eligible Customers taking transmission \nservice on behalf of Eligible Load, or propose appropriate Tariff revisions.  Specifically, \nISO-NE should explain whether the Tariff remains just and reasonable without (1) an \ninterim non-firm network transmission service while network upgrades are being \nconstructed (i.e., interim NITS) and (2) permanent firm and non-firm contract demand \ntransmission services (transmission service up to a specified MW quantity, i.e., the \ncontract level, on a firm or non-firm basis).  We note that the Commission has found it \njust and reasonable that, in order for an Eligible Customer to take interim NITS, firm \ncontract demand transmission service, and non-firm contract demand transmission \nservice, an Eligible Customer must have necessary control technologies and/or protection \n \n212 Id. P 199. \n213 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 101-103. \n214 See, e.g., PSEG November 21 ANOPR Comments at 20 (“The Commission’s \nlong-standing policy is to encourage reduced use of the transmission system, which \nwould in turn reduce upgrades to the transmission system, to the benefit of all \ntransmission customers.  For instance, if a co-located load’s use of the transmission \nsystem is limited (or to a lesser degree) than other traditional in front of the meter loads, \nit should be responsible for costs based on its limited use.”)."},{"page":60,"startToken":24166,"endToken":24578,"text":"Docket No. EL26-72-000 \n- 60 - \nsystems, which may include a special protection scheme, to limit its energy withdrawals \nto its approved level.215 \n Finally, we preliminary find that ISO-NE’s Tariff is unjust and unreasonable \nbecause it allows load with BTMG to net its BTMG against its load for purposes of \ncalculating Regional Network Service charges.  In the PJM Co-Location Order, the \nCommission found that PJM’s BTMG rules, which allowed load serving entities that \nprovide service to loads with qualifying BTMG to reduce their costs by netting output \nfrom BTMG in the calculation of their peak demand for the purpose of determining NITS \ncharges, were unjust and unreasonable.216  The Commission concluded that PJM’s \nBTMG rules were no longer consistent with cost causation principles because large loads \nconfigured in a BTMG arrangement with significant generation will raise cost shifting \nconcerns compared to loads pursuing smaller amounts of netting.217  The Commission \nalso found that such rules could lead to reliability and resource adequacy risks because \nPJM is obligated to serve transmission customers using BTMG, but does not consider \nsuch customers in transmission and resource adequacy planning.218  The Commission \ndirected PJM to revise its retail BTMG rules, including establishing a MW threshold for \nthe amount of load at a particular electrical location that network customers may net by \nusing BTMG.219  We are similarly concerned that ISO-NE’s Tariff allows Network \nCustomers that provide service to loads with BTMG to reduce their Regional Network \nService charges because the definition of Monthly Regional Network Load, which is used \nto calculate the Regional Network Service charge, excludes load offset by the portion of \nthe output of a Generator Asset that serves load located behind the same retail customer \nmeter as the Generator Asset.220  ISO-NE should explain whether the Tariff remains just \nand reasonable even though it allows netting of BTMG from load for purposes of \ndetermining Regional Network Service charges for loads configured in a BTMG \narrangement or propose Tariff revisions.  Recognizing potential impacts on existing \ncustomers, we note that ISO-NE may explain whether current BTMG rules for customers \nthat fall below a new MW materiality threshold for the amount of load at a particular \n \n215 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n216 PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 7, 186. \n217 Id. P 186. \n218 Id. \n219 Id. P 221. \n220 ISO-NE Tariff, § II.21.2; see also ISO New Eng. Inc., 178 FERC ¶ 61,086 \n(2022)."},{"page":61,"startToken":24578,"endToken":24978,"text":"Docket No. EL26-72-000 \n- 61 - \nelectrical location that Network Customers may net using BTMG remain just and \nreasonable. \nD. \nExtending New Transmission Services to Eligible Customers Taking \nService on Behalf of Flexible Large Loads \n In 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 loads221 can quickly and verifiably adjust \ntheir consumption in response to system conditions or price signals.222  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 \nfor network upgrades, among other potential benefits.223  In recognition of this flexibility, \nmany commenters support new transmission services that reflect the operational \ncapabilities of flexible large loads, including interim NITS while network upgrades are \nconstructed, and non-firm transmission service.224   \n \n221 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. \n222 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 November \n21 ANOPR Comments at 2-4; Digital Energy Council November 21 ANOPR Comments \nat 1; EDF Power November 21 ANOPR Comments at 4; Emerald November 21 ANOPR \nComments at 2; Verrus November 21 ANOPR Comments at 4. \n223 See, e.g., AEMA November 21 ANOPR Comments at 5; ELCON November \n21 ANOPR Comments at 9; Emerald November 21 ANOPR Comments at 6-7; Institute \nfor Progress November 21 ANOPR Comments at 11; Land Trust Alliance November 21 \nANOPR Comments at 10; LS Power November 21 ANOPR Comments at 5; Microsoft \nNovember 21 ANOPR Comments at 10-11; National Grid November 21 ANOPR \nComments at 19-20; OMS November 21 ANOPR Comments at 13-14; Southeast PIOs \nNovember 21 ANOPR Comments at 50. \n224 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 at \n3-4."},{"page":62,"startToken":24978,"endToken":25345,"text":"Docket No. EL26-72-000 \n- 62 - \n We preliminarily find that ISO-NE’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 ISO-NE \nare Regional Network Service, Local Network Service, and firm and non-firm Local \nPoint-to-Point Transmission Service.225  While these remain just and reasonable options \nfor an Eligible Customer to take on behalf of a flexible large load, based on the record \nbefore us, we preliminarily find that new transmission services should be available to \nreflect the operational reality that large loads may use the transmission system to \ndiffering extents and certain large loads are willing and able to limit their use of the \ntransmission system under certain conditions.226  As explained above, 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.227  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 \nflexibility can avoid inefficient and costly transmission system build-out.228  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 \n \n225 See supra P 20 (describing existing transmission services in ISO-NE). \n226 See supra P 101. \n227 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at P 103. \n228 See supra P 101; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at      \nPP 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)."},{"page":63,"startToken":25345,"endToken":25779,"text":"Docket No. EL26-72-000 \n- 63 - \ntimely interconnect flexible large loads.229  Entities in the ISO-NE footprint acknowledge \nthe importance of facilitating load flexibility.230 \n Therefore, we are concerned that ISO-NE’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.  ISO-NE should explain \nwhether the Tariff remains just and reasonable without the transmission services \ndescribed by the Commission in the PJM Co-Location Order, with regional variation as \nappropriate, being available to Eligible Customers taking transmission service on behalf \nof flexible large loads, or propose appropriate Tariff revisions.  Specifically, ISO-NE \nshould explain whether the Tariff remains just and reasonable without (1) an interim  \nnon-firm network transmission service while network upgrades are being constructed \n(i.e., interim NITS) and (2) permanent firm and non-firm contract demand transmission \nservices (transmission service up to a specified MW quantity, i.e., the contract level, on a \nfirm or non-firm basis).  Finally, we note that the Commission has found it just and \nreasonable that, in order for an Eligible Customer to take interim NITS, firm contract \ndemand transmission service, and non-firm contract demand transmission service, an \nEligible Customer must have necessary control technologies and/or protection systems, \nwhich may include a special protection scheme, to limit its energy withdrawals to its \napproved level.231 \nE. \nInterconnection Customers Serving Electrically Proximate Large Load \nand Co-Located Load \n In 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.232  Commenters argue that studies that consider large load and generation \n \n229 See supra P 101; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at      \nPP 201 (finding that the interim, non-firm transmission service will facilitate the “timely” \nprovision of transmission service and that “[t]his willingness to curtail would potentially \nallow them to obtain service more quickly”), 205 (recognizing that parties argue that co-\nlocated loads may be able to receive transmission service faster with use of a new, limited \ntransmission service product than they would if they selected NITS, to the extent that \nproviding NITS would require network upgrades that the limited transmission service \nwould not). \n230 See, e.g., Maine Public Advocate November 21 ANOPR Comments at 4-5; \nState Entities November 21 ANOPR Comments at 8. \n231 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n232 See e.g., DCC November 21 ANOPR Comments at 5-6; DTE November 21"},{"page":64,"startToken":25779,"endToken":26140,"text":"Docket No. EL26-72-000 \n- 64 - \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.233  As a result, this can speed up the interconnection process for both large loads \nand generation, and shorten energization timelines,234 which commenters contend \nreduces uncertainty for both parties235 and “is necessary to match the pace of AI \ninnovation in the United States.”236  CEBA also highlights that cost and timeline factors \ndrive developers to submit multiple requests for price and timing discovery, which \ninflates queue volumes, distorts demand and supply forecasts, and causes significant \ndelays when projects withdraw late after finding costs or energization timelines \nuneconomic.237  Other benefits to a joint study identified by commenters include \nimproving load forecasting and siting decisions238 and reducing the need for critical \nsupply chain components.239   \n Commenters 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 \n \nANOPR Comments at 11; Google November 21 ANOPR Comments at 7; International \nEnergy Credit Association November 21 ANOPR Comments at 10; Terraflux November \n21 ANOPR Comments at 1. \n233 AEU November 21 ANOPR Comments at 13; ClearPath November 21 \nANOPR Comments at 4; DCC November 21 ANOPR Comments at 5; DTE November \n21 ANOPR Comments at 8-11; ENGIE November 21 ANOPR Comments at 6; Entergy \nNovember 21 ANOPR Comments at 5; Geronimo November 21 ANOPR Comments at \n17-18; Information Technology Industry Council November 21 ANOPR Comments at 2. \n234 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. \n235 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 \nANOPR Comments at 8. \n236 Microsoft November 21 ANOPR Comments at 8-9. \n237 CEBA November 21 ANOPR Comments at 8. \n238 ELCON November 21 ANOPR Comments at 5; Maryland Commission \nNovember 21 ANOPR Comments at 6-7.  \n239 AEU November 21 ANOPR Comments at 13."},{"page":65,"startToken":26140,"endToken":26512,"text":"Docket No. EL26-72-000 \n- 65 - \nstudies and inefficient system build-out.240  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 have \nreliably served adjacent load growth.241   \n Commenters 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.242  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.243  Similarly, Helion contends that more than half of U.S. developers now \nidentify interconnection delays as the single biggest barrier to adding new generation \ncapacity.244  Commenters contend that if large load interconnection proceeds more \nquickly than new generation can come online, the result could be price increases for \nconsumers.245   \n A number of commenters support expedited interconnection studies for new \ngeneration paired with load.246  Some commenters argue that one solution to generator \n \n240 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. \n241 Eolian May 19 ANOPR Comments at 10. \n242 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.  \n243 Oracle November 21 ANOPR Comments at 1. \n244 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)). \n245 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR \nComments at 6-7, 11.  \n246 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."},{"page":66,"startToken":26512,"endToken":26897,"text":"Docket No. EL26-72-000 \n- 66 - \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.247  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.248  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.249   \n1. \nJurisdiction \n The Commission’s statutory authority includes jurisdiction over the wholesale sale \nand transmission of electricity in interstate commerce, including the facilities used for \nsuch sale and transmission.250  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.251  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 \n \n247 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.  \n248 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. \n249 Constellation June 5 ANOPR Comments at 8-9. \n250 16 U.S.C. § 824(b)(1). \n251 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.”)."},{"page":67,"startToken":26897,"endToken":27301,"text":"Docket No. EL26-72-000 \n- 67 - \ngenerator’s point of interconnection.”252  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 We recognize that states have exclusive authority over resource planning and the \ngeneration mix within their boundaries.253  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,254 and has approved interconnection processes that allow \ncertain generating facilities to interconnect more quickly by replacing a retiring existing \ngenerating facility.255   \n2. \nDefinitions \n For 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,256 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 \n \n252 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. \n253 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 (citing \n16 U.S.C. § 824(b)(1)).  \n254 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, \n163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order No. \n845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B,        168 \nFERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; PJM \nInterconnection, L.L.C., 190 FERC ¶ 61,083 (2025). \n255 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); \nMidcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019).  \n256 See supra P 56."},{"page":68,"startToken":27301,"endToken":27730,"text":"Docket No. EL26-72-000 \n- 68 - \nconsider proposed revisions to this definition that ensure it is appropriately tailored to \nISO-NE’s transmission system. \n3. \nTariff Provisions \n We preliminarily find that ISO-NE’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 this \norder,257 that has a high peak load (i.e., large co-located loads that are 50 MW or \ngreater).258  Specifically, we preliminarily find that ISO-NE’s Tariff appears to be unjust \nand 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 ISO-NE’s Tariff lacks, for example, \ngenerator interconnection study procedures and generator interconnection services that \nreflect (a) an interconnection customer’s commitment in an interconnection agreement to \nlimit a generating facility’s output to match the hourly forecast of an electrically \nproximate large load or large co-located load; and/or (b) a generating facility with \nnecessary control technologies and/or protection systems, which may include a special \nprotection scheme,259 that ensure that the injection does not exceed the limit in the \nexisting or new interconnection agreement.  Where a generating facility’s output is \nmatched to the demand of the electrically proximate large load or large co-located load or \nif the generating 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,260 thereby potentially \nreducing the need for network upgrades, which can accelerate the generator \n \n257 See supra P 86. \n258 We note that generator interconnection service in and of itself does not convey \ntransmission service. \n259 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n260 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."},{"page":69,"startToken":27730,"endToken":28183,"text":"Docket No. EL26-72-000 \n- 69 - \ninterconnection process.261  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.262   \n As 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.263  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 upgrades costs.264  The same result may occur in the absence of new \n \n261 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.”).  \n262 See AEP December 5 ANOPR Comments at 1; Base Power November 21 \nANOPR Comments at 7; CEBA November 21 ANOPR Comments at 8; DCC November \n21 ANOPR Comments at 6 (asserting that a clear framework to study large loads paired \nwith generation would resolve development bottlenecks); Eolian November 21 ANOPR \nComments at 18-19; Eolian May 19 ANOPR Comments at 2; Google November 21 \nANOPR Comments at 7 (calling for nationwide rules enabling proximate load-generation \ninterconnection to “accelerate the pace at which new generation comes online”); \nLongroad November 21 ANOPR Comments at 8. \n263 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. \n264 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible"},{"page":70,"startToken":28183,"endToken":28614,"text":"Docket No. EL26-72-000 \n- 70 - \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.265   \n SPP 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.266  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 \nsame local area.”267  We do not expect or propose that ISO-NE adopt an identical process \nto SPP’s HILLGA process, nor do we preliminarily find that the absence of Tariff \nprovisions specifically mirroring SPP’s Tariff renders ISO-NE’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.268  To the extent that the interconnection customer’s \n \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.”). \n265 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).  \n266 SPP HILL Order, 194 FERC ¶ 61,031. \n267 Id. P 64. \n268 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 ISO-NE’s transmission system \nmay warrant consideration of a more limited definition of electrically proximate.  See \nDuke November 21 ANOPR Comments at 21-22; DTE November 21 ANOPR"},{"page":71,"startToken":28614,"endToken":29043,"text":"Docket No. EL26-72-000 \n- 71 - \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 Another potentially reasonable approach could be to develop a generator \ninterconnection study process that would allow the use of existing ERIS or NRIS of an \nexisting generator to connect a new generating facility and a new large load behind the \nsame point of interconnection of the existing generator with necessary control \ntechnologies and/or protection systems, which may include a special protection scheme, \nthat ensure that the net injection does not exceed the amount in the existing generator \ninterconnection agreement.269  Such an approach could expedite the interconnection \nstudy process for a generator planning to serve an electrically proximate (in this case at \nthe same point of interconnection) large load.270  An additional potentially reasonable \napproach could be a new load-limited generator interconnection service that allows a new \ngenerating facility and new large co-located load seeking to interconnect behind the same \nnew point of interconnection, with necessary control technologies and/or protection \nsystems, which may include a special protection scheme, to ensure that there is no \ninjection to the transmission system.271  It may be reasonable for such a load-limited \ngenerator interconnection service to be or not to be of an interim nature.  We invite    \nISO-NE and/or Participating Transmission Owners, in responding to this order or in an \nFPA section 205 filing, to submit original proposals designed to address the concerns \nexpressed herein and tailored to their unique circumstances.  \n \nComments at 8-11 (asserting that studying large loads with electrically proximate \ngeneration streamlines interconnection and reduces upgrades); AEU November 21 \nANOPR Comments at 13-15. \n269 See Constellation June 5 ANOPR Comments at 1-2, 10-13. \n270 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”). \n271 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 \nANOPR Comments at 13-14."},{"page":72,"startToken":29043,"endToken":29499,"text":"Docket No. EL26-72-000 \n- 72 - \n We 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 ISO-NE’s current \ngenerator interconnection process failing to keep pace with the new large loads seeking to \nbe integrated onto ISO-NE’s transmission system.272  We preliminarily find that this \noutcome may be unjust and unreasonable because reliance on ISO-NE’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 ISO-NE 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 \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 ISO-NE to consider, in responding to these concerns, \nwhat type of transmission service an Eligible Customer will need to take on behalf of the \n \n272 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":73,"startToken":29499,"endToken":29890,"text":"Docket No. EL26-72-000 \n- 73 - \nelectrically proximate large load or large co-located load.273  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.274 \nF. \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.275  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 \ndrives up costs to ratepayers.276  We are concerned that ISO-NE and load serving entities \nare unable to plan adequate generation to serve all load at the pace such load seeks to \nconnect.   \n We recognize that ISO-NE is currently engaged with stakeholders to improve \nresource adequacy through the Capacity Auction Reforms Seasonal/Accreditation Key \nProject, which seeks to better address seasonal reliability challenges and to more \naccurately reflect resource contributions to resource adequacy.277  Additionally, ISO-NE \nis engaging with transmission owners regarding potential large load interconnections, and \nis communicating with states to understand any potential policies creating incentives for \n \n273 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. \n274 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. \n275 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.  \n276 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. \n277 See ISO-NE, Capacity Auction Reforms Key Project, https://www.iso-\nne.com/committees/key-projects/capacity-auction-reforms-key-project."},{"page":74,"startToken":29890,"endToken":30338,"text":"Docket No. EL26-72-000 \n- 74 - \ndata centers and to share information on how ISO-NE would review such proposed \ndevelopments.278  Accordingly, we direct ISO-NE to submit in Docket No. EL26-72-000, \nwithin 30 days of the date of issuance of this order, a detailed informational report on any \nproposals under consideration in its stakeholder process to address the issue of resource \nadequacy to serve new large loads.  We also strongly encourage new proposals to the \nextent necessary to address these concerns.  The informational report must include a \ndetailed schedule of key milestones, such as stakeholder or ISO-NE Board votes, that \nincludes the estimated date on which ISO-NE expects to file any such proposals with the \nCommission.  Additionally, as part of this informational report, we direct ISO-NE to \nidentify any ongoing stakeholder processes that aim to increase the pace of adding \ngenerating capacity in the ISO-NE region.  The informational report must include a \ndetailed schedule of such initiatives, including timing of the stakeholder process and \ndates 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 ISO-NE and the Participating Transmission Owners, in \nresponding to the order to show cause, should protect existing commercial arrangements \nincluding:  (1) what would be a reasonable implementation period to ensure minimal \ndisruption to such existing commercial arrangements, and (2) how to allow a reasonable \namount of time to finalize ongoing agreements that are nearing completion as of the date \nsuch Tariff provisions are filed 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 \nISO-NE’s Tariff and/or processes.  Specifically, what, if any, potential impacts on \nregional and local transmission planning would arise from the introduction of the new \ntransmission services discussed herein?  For example, when planning for load growth, \nhow would transmission providers and planners account for flexible large loads’ potential \n \n278 ISO-NE Letter at 1-2."},{"page":75,"startToken":30338,"endToken":30770,"text":"Docket No. EL26-72-000 \n- 75 - \npreference to take the new transmission services, including potential uncertainties around \nthe type, location, and quantity of such expected loads?     \n Today’s order preliminarily finds that ISO-NE’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 upgrades 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. \n Today’s order preliminarily finds that ISO-NE’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 ISO-NE 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 technologies, \ninclusion in the study report to the Eligible Customer seeking transmission service on \nbehalf of large load of a sufficiently clear demonstration of why alternative transmission \ntechnologies are not feasible (i.e., would not resolve reliability violations identified or \nmeet the relevant planning criteria) or would not result in lower costs or a faster timeline \nfor accommodating the transmission service request.  As noted above, to the extent \nstakeholders believe that specific characteristics of providing transmission service to \nEligible Customers on behalf of large loads warrant requirements beyond those \ncontemplated here, we seek further briefing.  \n Today’s order preliminarily finds that ISO-NE 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 ISO-NE allow an interconnection customer’s \ngenerating facility serving electrically proximate large load or large co-\nlocated load to participate in ISO-NE’s energy and ancillary services"},{"page":76,"startToken":30770,"endToken":31194,"text":"Docket No. EL26-72-000 \n- 76 - \nmarket, and if ISO-NE were to allow them to participate, what restrictions \nor mitigation would ISO-NE apply? \nb. To the extent that ISO-NE 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 ISO-NE account \nfor the generating facilities serving electrically proximate large load or \nlarge co-located load in the resource adequacy construct?  If applicable, \nwould ISO-NE allow the generating facilities serving electrically proximate \nlarge load or large co-located load to participate in ISO-NE’s capacity \nmarket?  If so, would ISO-NE accredit these generating facilities using the \nsame method as other ISO-NE generating facilities? \nThe Commission orders: \n \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. EL26-72-000 as discussed in the body of this order. \n(B) \nISO-NE and the Participating Transmission Owners are hereby directed, \nwithin 60 days of the date of the order, either:  (1) to show cause as to why the Tariff \nremains just and reasonable and not unduly discriminatory or preferential; or (2) to \nexplain what changes to the Tariff they believe would remedy the identified concerns if \nthe Commission 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(C) \nISO-NE is directed to submit an informational report within 30 days of the \ndate of issuance of this order, as discussed in the body of this order. \n(D) \nAny interested person desiring to be heard in Docket No. EL26-72-000 \nmust file a notice of intervention or motion to intervene, as appropriate, with the Federal \nEnergy Regulatory Commission, 888 First Street, NE, Washington, DC  20426, in \naccordance 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"},{"page":77,"startToken":31194,"endToken":31382,"text":"Docket No. EL26-72-000 \n- 77 - \ncourier) delivery to Federal Energy Regulatory Commission, 12225 Wilkins Avenue, \nRockville, MD  20852. \n(E) \nInterested entities may respond within 30 days of ISO-NE’s and the \nParticipating Transmission Owners’ filing, addressing either or both of:  (1) whether the \nTariff remains just and reasonable and not unduly discriminatory or preferential; and (2) \nif not, what changes 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 No. \nEL26-72-000. \n(G) \nThe refund effective date in Docket No. EL26-72-000 pursuant to section \n206 of the FPA shall be the date of publication in the Federal Register of the notice \ndiscussed 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  \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  attached. \n \n \n \n  Commissioner LaCerte is concurring with a separate statement \n  attached. \n \n( S E A L ) \n \n \n \n \n \n \n \n \n \nDebbie-Anne A. Reese, \nSecretary."},{"page":78,"startToken":31382,"endToken":31613,"text":"Docket No. EL26-72-000 \n- 78 - \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  \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 Corporation279 \nAmerican Public Gas Association \nAmerican Public Power Association (APPA) \nAmerican Terawatt, Inc. (American Terawatt) \nAmerican Transmission Company LLC (ATC)280 \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 \n279 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. \n280 ATC submitted comments on behalf of itself and its corporate manager ATC \nManagement Inc."},{"page":79,"startToken":31613,"endToken":31812,"text":"Docket No. EL26-72-000 \n- 79 - \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)281 \nDigital Energy Council  \nDigital Power Network \nDistributed Capacity Parties282 \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 Trading Institute \n \n281 The Illinois Attorney General joined the Joint Consumer Advocates in filing \nreply comments. \n282 Distributed Capacity Parties include:  Clovereleaf Infrastructure; Spark \nCommunity Investment d/b/a Sparkfund; and Voltus, Inc."},{"page":80,"startToken":31812,"endToken":32042,"text":"Docket No. EL26-72-000 \n- 80 - \nENGIE North America, Inc. (ENGIE) \nEntergy Services, LLC (Entergy)283 \nEnvironmental Law & Policy Center \nEolian L.P. (Eolian) \nEquinix, Inc. \nesVolta, LP \nETX Upstream, LLC \nEversource Energy (Eversource)284 \nExelon Corporation (Exelon)285 \nFervo Energy Company (Fervo) \nFirstEnergy Service Company286 \nFront Door Technologies LLC \nFluence \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 \nHelion Energy (Helion) \nHerbert Schrayschuen \n \n283 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. \n284 Eversource submitted comments on behalf of its affiliates The Connecticut \nLight and Power Company, NSTAR Electric Company, and Public Service Company of \nNew Hampshire, and through its agent Eversource Energy Service Company. \n285 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. \n286 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 Trans-\nAllegheny Interstate Line Company."},{"page":81,"startToken":32042,"endToken":32358,"text":"Docket No. EL26-72-000 \n- 81 - \nHeron Power Electronics Company  \nIndiana Energy Association \nIndicated PJM Transmission Owners287 \nIndustrial Customer Organizations (Industrial Customers)288 \nInformation Technology Industry Council \nInfrastructure Masons, Inc. (Infrastructure Masons) \nInstitute for Progress \nInternational Energy Credit Association \nInvenergy289 \nIron Mountain Data Centers, LLC \nISO New England, Inc. (ISO-NE) \n \n287 Indicated PJM Transmission Owners include:  AEP on behalf of Appalachian \nPower Company, Indiana Michigan Power Company, Kentucky Power Company, \nKingsport Power Company, Ohio Power Company, Wheeling Power Company, AEP \nAppalachian Transmission Company, Inc., AEP Indiana Michigan Transmission \nCompany, Inc., AEP Kentucky Transmission Company, Inc., AEP Ohio Transmission \nCompany, Inc., and AEP West Virginia Transmission Company, Inc.; AMP \nTransmission, LLC; City of Cleveland, Department of Public Utilities, Division of \nCleveland Public Power; City of Hamilton, OH; Dominion Energy Services, Inc. on \nbehalf of Virginia Electric and Power Company d/b/a Dominion Energy Virginia; Duke \nEnergy Corporation on behalf of its affiliates Duke Energy Ohio, Inc., Duke Energy \nKentucky, Inc., and Duke Energy Business Services LLC; Duquesne Light Company; \nEast Kentucky Power Cooperative; Exelon Corporation, on behalf of Atlantic City \nElectric Company, Baltimore Gas and Electric Company, Commonwealth Edison \nCompany, Commonwealth Edison Company of Indiana, Inc., Delmarva Power & Light \nCompany, PECO Energy Company, and Potomac Electric Power Company; FirstEnergy \nService Company, as agent for its affiliates American Transmission Systems, \nIncorporated, Jersey Central Power & Light Company, Mid-Atlantic Interstate \nTransmission LLC, Keystone Appalachian Transmission Company, The Potomac Edison \nCompany, Monongahela Power Company and Trans-Allegheny Interstate Line \nCompany; Old Dominion Electric Cooperative; PPL Electric Utilities Corporation; \nRockland Electric Company; Southern Maryland Electric Cooperative, Inc.; UGI Utilities \nInc; and Wabash Valley Power Association, Inc. \n288 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 \n289 Invenergy includes:  Invenergy Wind Development North America LLC, \nInvenergy Solar Development North America LLC, and Invenergy Thermal Development \nHoldings LLC."},{"page":82,"startToken":32358,"endToken":32646,"text":"Docket No. EL26-72-000 \n- 82 - \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 Parties290 \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 (Maine Public Advocate) \nMaryland Energy Administration  \nMaryland Public Service 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)291  \n \n290 Load Flexibility Parties include:  Enerwise Global Technologies, LLC d/b/a \nCPower, Enel North America, Inc., and Voltus, Inc. \n291 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 \ncorporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric"},{"page":83,"startToken":32646,"endToken":32949,"text":"Docket No. EL26-72-000 \n- 83 - \nMississippi Public Service Commission \nMissouri Public Service Commission \nMonitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor for \nPJM \nNathan Peterson \nNational Association of Regulatory Utility Commissioners (NARUC) \nNational Association of State Utility Consumer Advocates \nNational Conference of State Legislatures (NCSL) \nNational Congress of American Indians \nNational Grid PLC (National Grid)292 \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 (NESCOE) \nNew England Consumer-Owned Systems293 (together with Energy New England, LLC,  \nNew England Consumer-Owned Systems) \nNew England Public Systems294 \n \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 \n292 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 Hydro-\nTransmission Electric Company, Inc.; and Massachusetts Electric Company. \n293 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. \n294 New England Public Systems include:  Connecticut Municipal Electric \nCooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont"},{"page":84,"startToken":32949,"endToken":33181,"text":"Docket No. EL26-72-000 \n- 84 - \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 Owners295 \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 \nPew Charitable Trusts Energy Modernization Project \nPJM Interconnection, LLC  \nPower for Tomorrow \nPPL Corporation296 \n \nPublic Power Supply Authority. \n295 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. \n296 PPL Corporation submitted comments on behalf of the PPL Companies, which"},{"page":85,"startToken":33181,"endToken":33420,"text":"Docket No. EL26-72-000 \n- 85 - \nPrime Mover Institute \nPSEG Companies (PSEG)297 \nPublic Citizen, Inc. \nPublic Interest Organizations (PIOs)298 \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)299 \nSouthern California Edison Company (Southern California Edison) \nSouthern Companies300 \nSouthern Maryland Electric Cooperative, Inc. \nSouthwest Power Pool, Inc.  \n \ninclude PPL Electric Utilities Corporation, Louisville Gas & Electric Company and \nKentucky Utilities, and The Narragansett Electric Company d/b/a Rhode Island Energy. \n297 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. \n298 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. \n299 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. \n300 Southern Companies include:  Georgia Power Company, Alabama Power \nCompany, and Mississippi Power Company."},{"page":86,"startToken":33420,"endToken":33692,"text":"Docket No. EL26-72-000 \n- 86 - \nSouthwest Power Pool Transmission Owner Group301 \nSplight Inc. (Splight) \nState Entities302 \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  \nMembers303 \nU.S. Representatives304 \nU.S. Senate Committee on Energy and Natural Resources \nU.S. Senators305 \n \n301 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. \n302 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. \n303 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking \nMember, Subcommittee on Energy). \n304 The U.S. Representatives that submitted comments include:  Suhas \nSubramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr. \n305 The U.S. Senators that submitted comments include:  Edward J. Markey, Chris \nVan Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and"},{"page":87,"startToken":33692,"endToken":33734,"text":"Docket No. EL26-72-000 \n- 87 - \nU.S. Senator Jon Ossoff \nUnion of Concerned Scientists (UCS) \nVantage Data Centers (Vantage) \nVerrus \nVirginia State Corporation Commission \nVistra Corp. (Vistra) \nWashington Utilities and Transportation Commission \nWIRES \nWisconsin Electric Company \nWisconsin Public Service Corporation  \n \n \nAdam B. Schiff."},{"page":88,"startToken":33734,"endToken":34012,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nISO New England Inc. \nCentral Maine Power Company  \nThe Connecticut Light and Power Company \nFitchburg Gas and Electric Light Company \nGreen Mountain Power Corporation  \nMaine Electric Power Company  \nThe Narragansett Electric Company \nNew England Power Company \nNew Hampshire Transmission, LLC  \nNSTAR Electric Company \nPublic Service Company of New Hampshire \nThe United Illuminating Company  \nUnitil Energy Systems, Inc.  \nVermont Electric Cooperative, Inc. \nVermont Electric Power Company, Inc. \nVermont Transco LLC  \nVersant Power  \nDocket No. EL26-72-000 \n \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 \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"},{"page":89,"startToken":34012,"endToken":34463,"text":"Docket No. EL26-72-000 \n \n- 2 - \n \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, \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 \n \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). \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"},{"page":90,"startToken":34463,"endToken":34893,"text":"Docket No. EL26-72-000 \n \n- 3 - \n \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 \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 \n \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. \n8 See, e.g., Comments of Talen Energy Corporation, Docket No. RM26-4, at 5-6 \n(filed Nov. 21, 2025)."},{"page":91,"startToken":34893,"endToken":35372,"text":"Docket No. EL26-72-000 \n \n- 4 - \n \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. \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 \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":92,"startToken":35372,"endToken":35497,"text":"Docket No. EL26-72-000 \n \n- 5 - \n \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.  For these reasons, I respectfully concur.   \n \n \n________________________ \nLaura V. Swett \nChairman"},{"page":93,"startToken":35497,"endToken":35767,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nISO New England Inc. \nCentral Maine Power Company  \nThe Connecticut Light and Power Company \nFitchburg Gas and Electric Light Company \nGreen Mountain Power Corporation  \nMaine Electric Power Company  \nThe Narragansett Electric Company \nNew England Power Company \nNew Hampshire Transmission, LLC  \nNSTAR Electric Company \nPublic Service Company of New Hampshire \nThe United Illuminating Company  \nUnitil Energy Systems, Inc.  \nVermont Electric Cooperative, Inc. \nVermont Electric Power Company, Inc. \nVermont Transco LLC  \nVersant Power \nDocket No. EL26-72-000 \n \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"},{"page":94,"startToken":35767,"endToken":36227,"text":"Docket No. EL26-72-000 \n- 2 - \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***** \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 \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). \n2 See Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":95,"startToken":36227,"endToken":36655,"text":"Docket No. EL26-72-000 \n- 3 - \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 \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 \n \n3 NERC, Large Loads Action Plan Q1 2026 Update (Apr. 2026), \nhttps://www.nerc.com/globalassets/initiatives/large-loads-action-plan/llap-quarterly-\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."},{"page":96,"startToken":36655,"endToken":37094,"text":"Docket No. EL26-72-000 \n- 4 - \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 \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 \n \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.  \n6 PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2026), (Rosner, Comm’r, \nconcurring) at P 3."},{"page":97,"startToken":37094,"endToken":37553,"text":"Docket No. EL26-72-000 \n- 5 - \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 \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-\n \n7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026)."},{"page":98,"startToken":37553,"endToken":37596,"text":"Docket No. EL26-72-000 \n- 6 - \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":99,"startToken":37596,"endToken":37598,"text":"Figure 1"},{"page":100,"startToken":37598,"endToken":37600,"text":"Figure 2"},{"page":101,"startToken":37600,"endToken":37893,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nISO New England Inc. \nCentral Maine Power Company  \nThe Connecticut Light and Power Company \nFitchburg Gas and Electric Light Company \nGreen Mountain Power Corporation  \nMaine Electric Power Company  \nThe Narragansett Electric Company \nNew England Power Company \nNew Hampshire Transmission, LLC  \nNSTAR Electric Company \nPublic Service Company of New Hampshire \nThe United Illuminating Company  \nUnitil Energy Systems, Inc.  \nVermont Electric Cooperative, Inc. \nVermont Electric Power Company, Inc. \nVermont Transco LLC  \nVersant Power \nDocket No. EL26-72-000 \n \n \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"},{"page":102,"startToken":37893,"endToken":38351,"text":"Docket No. EL26-72-000 \n- 2 - \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 \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.  \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":103,"startToken":38351,"endToken":38855,"text":"Docket No. EL26-72-000 \n- 3 - \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 \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"},{"page":104,"startToken":38855,"endToken":39171,"text":"Docket No. EL26-72-000 \n- 4 - \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 \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 \n \n3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026). \n4 See id. P 456."},{"page":105,"startToken":39171,"endToken":39428,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nISO New England Inc. \nCentral Maine Power Company  \nThe Connecticut Light and Power Company \nFitchburg Gas and Electric Light Company \nGreen Mountain Power Corporation  \nMaine Electric Power Company  \nThe Narragansett Electric Company \nNew England Power Company \nNew Hampshire Transmission, LLC  \nNSTAR Electric Company \nPublic Service Company of New Hampshire \nThe United Illuminating Company  \nUnitil Energy Systems, Inc.  \nVermont Electric Cooperative, Inc. \nVermont Electric Power Company, Inc. \nVermont Transco LLC  \nVersant Power  \nDocket No. EL26-72-000 \n \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"},{"page":106,"startToken":39428,"endToken":39865,"text":"Docket No. EL26-72-000 \n- 2 - \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 \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 \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":107,"startToken":39865,"endToken":40323,"text":"Docket No. EL26-72-000 \n- 3 - \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 \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 \n \n2 See, e.g., Mun. Light Bds. Of Reading and Wakefield v. FPC, 450 F.2d 1341, \n1348 (D.C. Cir. 1971) (stating that the FPA’s “primary aim is the protection of \nconsumers from excessive rates and charges”)."},{"page":108,"startToken":40323,"endToken":40718,"text":"Docket No. EL26-72-000 \n- 4 - \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 \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 \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). \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":109,"startToken":40718,"endToken":41197,"text":"Docket No. EL26-72-000 \n- 5 - \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 \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"},{"page":110,"startToken":41197,"endToken":41564,"text":"Docket No. EL26-72-000 \n- 6 - \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 \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. \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":111,"startToken":41564,"endToken":41701,"text":"Docket No. EL26-72-000 \n- 7 - \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.   \nFor these reasons, I respectfully concur.  \n \n \n________________________ \nJudy W. Chang \nCommissioner"},{"page":112,"startToken":41701,"endToken":41978,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nISO New England Inc. \nCentral Maine Power Company  \nThe Connecticut Light and Power Company \nFitchburg Gas and Electric Light Company \nGreen Mountain Power Corporation  \nMaine Electric Power Company  \nThe Narragansett Electric Company \nNew England Power Company \nNew Hampshire Transmission, LLC  \nNSTAR Electric Company \nPublic Service Company of New Hampshire \nThe United Illuminating Company  \nUnitil Energy Systems, Inc.  \nVermont Electric Cooperative, Inc. \nVermont Electric Power Company, Inc. \nVermont Transco LLC  \nVersant Power  \nDocket No. EL26-72-000 \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 ISO-NE’s Tariff that need to \nbe resolved 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 ISO-NE, 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 \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":113,"startToken":41978,"endToken":42447,"text":"Docket No. EL26-72-000 \n- 2 - \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 ISO-NE to design proposals in response to this show cause order \nthat dovetail with the efforts on the retail side to implement the Ratepayer Protection \nPledge, protect customers, and ensure that large loads cover the costs they incur to \nintegrate with the 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 ISO-NE, may be unjust and unreasonable and/or unduly discriminatory or \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":114,"startToken":42447,"endToken":42924,"text":"Docket No. EL26-72-000 \n- 3 - \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 \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, ISO-NE, 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  \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)."},{"page":115,"startToken":42924,"endToken":43320,"text":"Docket No. EL26-72-000 \n- 4 - \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 ISO-NE proceeding we initiate \nhere.  If we find your Tariff is in fact unjust and unreasonable and unduly discriminatory \nor preferential, 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______________________________ \nDavid LaCerte \nCommissioner \n \n \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[.]”)."}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":2562,"startToken":0,"endToken":256},{"p":2,"at":2562,"title":"D. Extending New Transmission Services to Eligible Customers Taking Service on","method":"printed heading","endPage":2,"endAt":2761,"startToken":256,"endToken":273},{"p":2,"at":2761,"title":"E. Interconnection Customers Serving Electrically Proximate Large Load and Co-","method":"printed heading","endPage":7,"endAt":2143,"startToken":273,"endToken":2300},{"p":7,"at":2143,"title":"I. 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Conclusion","method":"PDF bookmark","endPage":111,"endAt":36,"startToken":41568,"endToken":41569},{"p":111,"at":36,"title":"Conclusion","method":"printed heading","endPage":115,"endAt":2511,"startToken":41569,"endToken":43320}]}