{"document":{"slug":"e-12-nyiso-el26-69-000","title":"NYISO show cause order","issued":"2026-06-18","docket":"EL26-69-000","filer":"FERC","group":"June 18 orders","kind":"order","file":"docs/orders/e-12-nyiso-el26-69-000.pdf","url":"https://www.ferc.gov/media/e12-el26-69-000","sha256":"2cbbe4a06823bc8d86d40484159f655921db057cafd92a1d3c4a73389a5c1648","pages":119,"tokens":44897,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":102,"text":"195 FERC ¶ 61,216 \nUNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nBefore Commissioners:  Laura V. Swett, Chairman; \n                                        David Rosner, Lindsay S. See, \n                                        Judy W. Chang, and David LaCerte. \n \nNew York Independent System Operator, Inc. \nCentral Hudson Gas & Electric Corporation \nConsolidated Edison Company of New York, Inc.  \nLS Power Grid New York Corporation I \nNew York State Electric & Gas Corporation  \nNew York Transco LLC \nNextEra Energy Transmission New York, Inc. \nNiagara Mohawk Power Corp.  \nOrange and Rockland Utilities, Inc. \nRochester Gas and Electric Corporation   \nDocket No. EL26-69-000 \n \n \nORDER INSTITUTING PROCEEDING  \nUNDER SECTION 206 OF THE FEDERAL POWER ACT \n \n(Issued June 18, 2026)"},{"page":2,"startToken":102,"endToken":378,"text":"Docket No. EL26-69-000 \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. NYISO’s Existing Processes ....................................................................................... 20. \nA. Existing Tariff Processes ......................................................................................... 20. \n1. Firm Point-to-Point Transmission Service .......................................................... 21. \n2. NITS .................................................................................................................... 24. \n3. Load Interconnection Process .............................................................................. 27. \n4. Local Transmission Planning Process ................................................................. 30. \n5. Generator Interconnection ................................................................................... 31. \n6. Co-Located Load Interconnection Process .......................................................... 33. \nB. Recent Stakeholder Proceedings in NYISO ............................................................ 35. \nIII. Discussion ................................................................................................................... 38. \nA. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 44. \n1. Jurisdiction ........................................................................................................... 48. \n2. Tariff Provisions .................................................................................................. 55. \nB. Cost Shifting Risk Among Transmission Customers .............................................. 72. \n1. Jurisdiction ........................................................................................................... 74. \n2. Additional Cost Transparency ............................................................................. 77. \n3. Cost Recovery Agreements ................................................................................. 83. \nC. Co-Location Arrangements and Load with Behind the Meter Generation ............. 92. \n1. Definition ............................................................................................................. 94. \n2. Jurisdiction ........................................................................................................... 99. \n3. Tariff Provisions ................................................................................................ 101. \nD. Extending New Transmission Services to Eligible Customers Taking Service on \nBehalf of Flexible Large Loads ................................................................................. 111. \nE. Interconnection Customers Serving Electrically Proximate Large Load and Co-\nLocated Load .............................................................................................................. 114. \nF. Informational Report .............................................................................................. 128. \nIV. Briefing Questions .................................................................................................... 130. \n1. \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 \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);"},{"page":3,"startToken":378,"endToken":828,"text":"Docket No. EL26-69-000 \n- 3 - \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 \nnumber of unique challenges that large load integration poses for the reliable operation  \nof that system; and have debated how best to ensure that the rates, terms, and conditions \nof transmission service remain just and reasonable as more and more large loads are \n \n \n \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 (5) \nis not part of a co-location arrangement.  See infra P 64. \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.  In \nthis order, we will use the term co-location arrangement when referring to both the co-\nlocated load and the associated generating facility.  See infra P 95. \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":828,"endToken":1306,"text":"Docket No. EL26-69-000 \n- 4 - \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. \n2. \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, New York Independent System Operator, \nInc. (NYISO) has not yet proposed tariff revisions to address the challenges associated \nwith the integration of large and co-located loads, despite the fact that NYISO itself has \nrecognized challenges to the existing load interconnection process in its Tariff, including, \namong other things, the “limited opportunity” to identify reliability impacts, “limited \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. EL26-69-000. \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 120. \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":1306,"endToken":1692,"text":"Docket No. EL26-69-000 \n- 5 - \nrules for capturing impacts of load interconnection on the broader transmission system,” \nand that the large volume of requests may delay study timelines.9   \n3. \nAs discussed below, we find that NYISO’s existing Open Access Transmission \nTariff (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),10 and we direct NYISO and the Transmission Owners,11 \nwithin 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 Customers12 seeking transmission \nservice on behalf of large loads;  \n \n9 NYISO, Load Interconnection Process: Challenges and Considerations 16 (Feb. \n3, 2026), https://www.nyiso.com/documents/20142/56802634/04_Load_\ninterconnection_reform_2-3-26_TPAS_final.pdf/ (NYISO Challenges and \nConsiderations). \n10 16 U.S.C. § 824e. \n11 Transmission Owners refers to the entities listed in the caption of this order.  We \nrecognize that NYISO’s transmission owners include entities that are not subject to the \nCommission’s jurisdiction because they are not public utilities pursuant to section 201(f) \nof the FPA.  See 16 U.S.C. § 824(f); Sw. Power Pool, Inc., 180 FERC ¶ 61,022, at PP 44-\n45 (2022).  Accordingly, the Commission has not included Long Island Power Authority \nand New York Power Authority here as Transmission Owners that must respond to this \norder to show cause.  Nonetheless, the Commission retains the authority to review each \nentity’s formula rates as a component of NYISO’s Tariff in an order to show cause \ndirected towards NYISO, and NYISO must respond to this order regarding the non-\npublic utilities’ NYISO Tariff provisions on file with the Commission.  See Sw. Power \nPool, Inc., 180 FERC ¶ 61,022 at P 40. \n12 NYISO defines an Eligible Customer, in relevant part, as:  \n(i) An entity that is engaged, or proposes to engage, in the \nwholesale or retail electric power business including any \nelectric utility, power marketer, Federal power marketing \nagency, or any person generating Energy for sale for resale. . . \n[or] (ii) Any retail customer taking unbundled transmission \nservice pursuant to a state requirement that the Transmission"},{"page":6,"startToken":1692,"endToken":1995,"text":"Docket No. EL26-69-000 \n- 6 - \n(b) additional transparency concerning the Network Upgrade13 costs to \nprovide transmission service to Eligible Customers on behalf of large loads, \na pro forma cost recovery agreement between NYISO, 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;14 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 \n \n \nOwner offer the transmission service, or pursuant to a \nvoluntary offer of such service by the Transmission Owner, is \nan Eligible Customer under the Tariff.   \nNYISO, Open Access Transmission Tariff, § 1.5 (Definitions – E) (16.0.0) \n(NYISO Tariff). \n13 Capitalized terms not otherwise defined herein have the meanings ascribed to \nthem in the Tariff. \n14 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 229."},{"page":7,"startToken":1995,"endToken":2427,"text":"Docket No. EL26-69-000 \n- 7 - \n4. \nWe are also concerned with NYISO’s need to ensure adequate generation to serve \nnew large loads.15  We therefore direct NYISO to submit, within 30 days of the date of \nissuance of this order, an informational report on how NYISO intends to ensure that \nadequate generation will be available to serve existing and new large loads, as detailed \nlater in this order.   \n5. \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 NYISO and/or the Transmission \nOwners in response to this proceeding should (a) propose a reasonable implementation \nperiod to ensure minimal disruption to such existing commercial arrangements, and (b) \nallow a reasonable amount of time to finalize ongoing agreements that are nearing \ncompletion as of the date such Tariff provisions are filed with the Commission.  Such \nproposed Tariff revisions should include a reasonable effective date that accommodates \nsuch considerations regarding these existing commercial arrangements. \nI. \nBackground \nA. \nGrowth of Large and Co-Located Loads and ANOPR \n6. \nAs the Secretary explained in the ANOPR, electricity demand in the United States \nis expected to grow at an extraordinary pace in the near term, largely due to the rapid \ngrowth of large loads.16  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 \n \n15 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). \n16 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)."},{"page":8,"startToken":2427,"endToken":2819,"text":"Docket No. EL26-69-000 \n- 8 - \ntransmission system.17  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.18 \n7. \nOn April 16, 2026, the Commission issued an order regarding its intent to act with \nrespect to the ANOPR docket.19  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.’”20  After recognizing the Commission’s recent actions in \nproceedings involving issues associated with large loads,21 the Commission concluded \nthat it was clear that additional “action is warranted to support further progress where it is \nneeded.”22 \n8. \nNYISO’s and Transmission Owners’ comments in response to the ANOPR also \nrecognize the growth of large loads and highlight the unique challenges that integrating \n \n17 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). \n18 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. \n19 Interconnection of Large Loads to the Interstate Transmission Sys., 195 FERC  \n¶ 61,045 (2026) (Order Regarding Intent to Act). \n20 Id. P 2. \n21 Id. (citing PJM Co-Location Order, 193 FERC ¶ 61,217; SPP HILL Order,  \n194 FERC ¶ 61,031; Commonwealth Edison Co., 194 FERC ¶ 61,181; Tri-State \nGeneration & Transmission Ass’n, 193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, \nLLC, 193 FERC ¶ 61,237). \n22 Id. PP 3-4."},{"page":9,"startToken":2819,"endToken":3233,"text":"Docket No. EL26-69-000 \n- 9 - \nlarge loads poses to New York’s operation of the transmission system given their size, \noperational behavior, and unique potential to impact the transmission system.23  \nAccording to NYISO, only six large load projects totaling 1,045 MW were in its \ninterconnection queue in 2022.  As of November 2025, by contrast, more than 40 large \nload projects that could add more than 10,000 MW to the transmission system are in the \nqueue.  NYISO also notes that it has recently seen a decrease in available resources, \nwhich, when paired with the rapid growth of large loads and forecasted growth in \ndemand, will further diminish resource and reliability margins.24   \n9. \nAs discussed further below and as several commenters explain, NYISO has load \ninterconnection procedures that apply to load interconnection requests for projects that \nare greater than 10 MW connecting at a voltage level of 115 kV or above, or projects 80 \nMW or more connecting at a voltage level below 115 kV.25  The New York Commission \nasserts in the ANOPR proceeding that those procedures effectively facilitate the \ninterconnection of large loads and that NYISO is already working on potential \nimprovements to its large load interconnection processes.26  NYISO and the NYTOs, \nhowever, state that NYISO’s load addition process should be reviewed and enhanced to \naddress issues that have arisen because of the influx of large load proposals.27  NYISO \n \n23 NYISO November 21 ANOPR Comments at 2-3, 6-8; NYTOs November 21 \nANOPR Comments at 2. \n24 NYISO November 21 ANOPR Comments at 7-8 (citing NYISO, 2025-2034 \nComprehensive Reliability Plan (Nov. 21, 2025), \nhttps://www.nyiso.com/documents/d/guest/2025-2034-comprehensive-reliability-plan \n(NYISO 2025-2034 Comprehensive Reliability Plan); NYISO, 2023-2032 \nComprehensive Reliability Plan (Nov. 28, 2023), https://www.nyiso.com/documents/\n20142/2248481/2023-2032-Comprehensive-Reliability-Plan.pdf). \n25 NYISO November 21 ANOPR Comments at 2; see infra PP 27-29.  Proposed \nload interconnections that do not meet these criteria are subject to the procedures of the \napplicable transmission owner.  NYISO, Technical Bulletin No. 266, Load \nInterconnection Projects System Impact Study Procedure 1 (Nov. 7, 2025), \nhttps://www.nyiso.com/documents/20142/2931465/TB266-LoadInterconnection-\n20251107-Final.pdf/ (NYISO Technical Bulletin No. 266).  \n26 New York Commission November 21 ANOPR Comments at 2-5. \n27 NYISO November 21 ANOPR Comments at 3; NYTOs November 21 ANOPR \nComments at 2.  The NYTOs include:  Central Hudson Gas & Electric Corporation, \nConsolidated Edison Company of New York, Inc., New York Power Authority, New \nYork State Electric & Gas Corporation, Niagara Mohawk Power Corp., Orange and"},{"page":10,"startToken":3233,"endToken":3648,"text":"Docket No. EL26-69-000 \n- 10 - \nnotes that there are several challenges with its existing load interconnection process, such \nas:  (1) the large volume of requests may delay the completion of the Load System \nImpact Study (Load SIS), which already requires approximately nine months to \ncomplete;28 (2) resource adequacy is not currently considered in load interconnection \nstudies; (3) the “[l]imited opportunity to identify an individual load interconnection’s \ncontribution to reliability impacts” when considering several load interconnections \ncollectively; (4) the “limited rules for capturing impacts of the load interconnection on \nthe broader transmission system,” such as on Affected Systems; (5) the variability of \nfacilities-study practices and interconnection agreements requirements among the \nTransmission Owners; (6) the “limited process for evaluating material modifications to \nprojects;” and (7)  “[n]o specific process for studying co-located generator and load \ninterconnections.”29  \n10. \nNYTOs also recognize the benefits of implementing formalized processes for \nstudies related to the addition of large loads and that specific timelines can improve \ndiscipline and predictability.30  Additionally, National Grid states that its experience in \nNew York and New England confirms the need to define the “rules of the road” for large \nload interconnections.31  National Grid recognizes the urgency of this effort given that the \npace at which large loads are seeking interconnection is accelerating.  National Grid \nanticipates that a standardized set of rules for large load interconnections would be \n \nRockland Utilities, Inc., Long Island Power Authority, and Rochester Gas and Electric \nCorporation. \n28 See NYISO Technical Bulletin No. 266 at 3. \n29 NYISO Challenges and Considerations at 16; see NYISO, 2024 Reliability \nNeeds Assessment (RNA) 34-37 (Nov. 19, 2024), \nhttps://www.nyiso.com/documents/20142/2248793/2024-RNA-Report.pdf (noting a \ndramatic increase “over the past several years” in load interconnection requests and that \nthe increasing speed and scale with which large loads seek to interconnect in NYISO will \nhave “major impacts on future load growth and system risk”); Transcript, Large Loads \nCo-Located at Generating Facilities Technical Conference, Docket No. AD24-11-000, at \n63-64 (Nov. 1, 2024) (Zachary G. Smith, Senior Vice President of System and Resources \nPlanning, NYISO) (stating that the load interconnection provisions in NYISO’s Tariff \n“gives no clarity at all in terms of responsibility for facilities that are needed to \ninterconnect those loads, [or for] cost responsibility,” which creates confusion between \nutilities). \n30 See NYTOs November 21 ANOPR Comments at 19. \n31 National Grid November 21 ANOPR Comments at 2.  National Grid’s \nsubsidiary, Niagara Mohawk Power Corporation, is a Transmission Owner in New York."},{"page":11,"startToken":3648,"endToken":4101,"text":"Docket No. EL26-69-000 \n- 11 - \ncritical to addressing the uncertainties that both transmission owners and large loads such \nas data center developers frequently encounter during interconnection planning. 32  \nNational Grid contends that clear, predictable rules will enable timely and efficient \nintegration of these customers, supporting economic growth and innovation while \nmaintaining system reliability.  Commenters also note that reforms that encourage the \npairing of generation with electrically proximate load could streamline the addition of \nlarge loads and provide broad benefits to the New York transmission system.33 \n11. \nMoreover, many commenters in the ANOPR proceeding filed persuasive \ncomments documenting the need for clear and consistent tariff provisions to ensure \nregulatory and process certainty, fairness and consistency, and efficiency as large and co-\nlocated loads are added to the transmission system in increasing numbers.34  There is also \nbroad support for rules that help to ensure that other transmission customers are not \nunfairly burdened with additional costs or reliability impacts as large and co-located \nloads interconnect to the transmission system.35  In addition, many ANOPR commenters \n \n32 Id. at 7.  \n33 See NYTOs November 21 ANOPR Comments at 12 (noting that NYISO has in \nits 2026 stakeholder process prioritized initiatives that better integrate load with on-site \ngeneration, which could help shorten study timelines and modernize the current load-\ninterconnection process); National Grid November 21 ANOPR Comments at 17-18 \n(pointing to NYISO’s lengthy generation cluster study process and stating that \nencouraging such pairing can reduce transmission investment and improve resource \nadequacy while also advancing speed to power for large loads).  \n34 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; R \nStreet November 21 ANOPR Comments at 3; Switch December 5 ANOPR Comments at \n3; Tract November 21 ANOPR Comments at 5; Vantage November 21 ANOPR \nComments at 5-6; Vistra December 5 ANOPR Comments at 1-2. \n35 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"},{"page":12,"startToken":4101,"endToken":4475,"text":"Docket No. EL26-69-000 \n- 12 - \nhighlighted the need to efficiently integrate large loads, particularly data centers, to \nsupport national security priorities and economic development.36   \nB. \nRecent Proceedings Addressing Large and Co-Located Loads \n12. \nOver the past year, the Commission has begun to address, both sua sponte and in \nresponse to complaints and FPA section 20537 filings, the growing use of co-location \narrangements.38  The Commission’s orders in those proceedings have addressed the need \nfor clear and consistent tariff provisions regarding the rates, terms, and conditions of \nservice that apply to co-location arrangements and for transmission services that reflect \nEligible Customers taking transmission service on behalf of co-located loads and load \nwith behind the meter generation that are willing and able to limit their energy \nwithdrawals from the transmission system under certain conditions.  Several other \nCommission proceedings have addressed the challenges of integrating large loads onto \nthe transmission system, including the need for clear and consistent tariff provisions \nregarding the provision of transmission service to Eligible Customers on behalf of large \nloads and for interconnection customers serving electrically proximate large load.  As \nexplained below, these proceedings provide examples that will help to ensure that \njurisdictional transmission service is provided in a manner that is just and reasonable and \nmaintains reliability as large loads are integrated onto the transmission system and co-\nlocation arrangements become more common.  It is in this context that the Commission \nnow considers whether NYISO’s Tariff remains just and reasonable without similar \nprovisions. \n \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. \n36 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nDCC November 21 ANOPR Comments at 3; ECA November 21 ANOPR Comments  \nat 6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR \nComments at 2-3; Verrus December 5 ANOPR Comments at 2. \n37 16 U.S.C. § 824d. \n38 See PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order,  \n193 FERC ¶ 61,217, order on reh’g, PJM Co-Location Rehearing Order, 195 FERC  \n¶ 61,209; SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC  \n¶ 61,196."},{"page":13,"startToken":4475,"endToken":4858,"text":"Docket No. EL26-69-000 \n- 13 - \n1. \nPJM Co-Location Proceedings \n13. \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.39  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.40  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.41   \n14. \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 co-\nlocated load.42  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.43  Additionally, the Commission found that PJM’s behind the meter \ngeneration rules were no longer just and reasonable.44  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 \n \n39 See PJM Show Cause Order, 190 FERC ¶ 61,115. \n40 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.   \n41 PJM Co-Location Order, 193 FERC ¶ 61,217. \n42 Id. P 176.  \n43 Id. P 177. \n44 Id. P 179."},{"page":14,"startToken":4858,"endToken":5227,"text":"Docket No. EL26-69-000 \n- 14 - \norder to effectuate a co-location arrangement;45 (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 \nconstructed (interim NITS); (b) a new firm contract demand transmission service; or (c) a \nnew non-firm contract demand transmission service;46 (3) to revise the behind the meter \ngeneration rules and implement a transition process for existing behind the meter \ngeneration participants;47 and (4) to make several clarifications on how certain aspects of \nPJM’s generator interconnection process apply to interconnection customers seeking to \nserve co-located load.48   \n15. \nOn June 18, 2026, concurrently with the instant order, the Commission issued an \norder modifying the discussion in the PJM Co-Location Order and setting aside the order \nin part; accepting in part and rejecting in part PJM’s compliance filing, and directing a \nfurther compliance filing; and establishing as just and reasonable certain rates, terms, and \nconditions for the new transmission services (i.e., interim NITS, firm contract demand \ntransmission service, and non-firm contract demand transmission service).49 \n2. \nSPP High Impact Large Load and High Impact Large Load \nGeneration Assessment Processes \n16. \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.50  SPP’s tariff revisions established HILLs as a new \n \n45 Id. PP 187-192, 225-230. \n46 Id. PP 193-218.  The Commission also established a paper hearing to determine \nthe just and reasonable rates, terms, and conditions for the new transmission services.  Id. \nPP 219-220. \n47 Id. PP 221-224.  \n48 Id. PP 161, 231-236. \n49 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). \n50 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64."},{"page":15,"startToken":5227,"endToken":5645,"text":"Docket No. EL26-69-000 \n- 15 - \ncategory of load;51 imposed enhanced study requirements to enable SPP to assess the \nHILL’s reliability impacts on the transmission system;52 and created additional, ongoing \noperational requirements for transmission customers serving HILLs to ensure continued \nreliability of the transmission system.53  The tariff revisions also established the HILLGA \nprocess, a new generator interconnection service and related interconnection process to \nfacilitate the prompt interconnection of generating facilities that are specifically identified \nfor, and limited to, serving a HILL and are located no more than two substations away \nfrom the HILL.54   \n \n51 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). \n52 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). \n53 Id. P 18 (explaining that market participants registering a HILL must (1) follow \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). \n54 Id. P 27 (explaining that, under the HILLGA process, SPP proposes to study \nHILLGA requests to determine whether any network upgrades are needed to"},{"page":16,"startToken":5645,"endToken":6005,"text":"Docket No. EL26-69-000 \n- 16 - \n17. \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.”55  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.56  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.57  In addition, the Commission found that the proposed study \ndeposits would discourage speculative HILL study requests.58  Finally, the Commission \nconcluded that the proposed ongoing reliability requirements would allow SPP to \nmaintain reliable operation of its transmission system by increasing SPP’s visibility, \nproviding necessary data, and imposing real-time operational safeguards for HILLs.59  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.”60   \n \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).  \n55 Id. P 60. \n56 Id. P 61. \n57 Id. P 62. \n58 For the HILL delivery point study, SPP required a $10,000 non-refundable \napplication fee and a $100,000 study deposit, with an additional $200,000 study deposit if \nan Electromagnetic Transient study was also required.  Id. P 15.  For the HILL \nsupplemental load connection study, SPP allows the host transmission owner to require a \n$25,000 study deposit.  Id. P 16. \n59 Id. P 63. \n60 Id. P 64."},{"page":17,"startToken":6005,"endToken":6287,"text":"Docket No. EL26-69-000 \n- 17 - \n3. \nSPP Conditional High Impact Large Load Service \n18. \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).61  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.62  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.63  \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.64   \n19. \nThe Commission found that SPP had shown that unprecedented growth in large \nloads presents significant and unique operational and planning challenges.65  The \nCommission also found that SPP’s ability to add HILLs to its transmission system in a \ntimely manner may be limited due to delays in obtaining sufficient designated resources \nand completing network upgrades needed to provide long-term firm transmission service \nto such load.66  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.67 \n \n61 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. \n62 Id. P 7.  \n63 Id. PP 9-10. \n64 Id. P 9. \n65 Id. P 84. \n66 Id. \n67 Id."},{"page":18,"startToken":6287,"endToken":6680,"text":"Docket No. EL26-69-000 \n- 18 - \nII. \nNYISO’s Existing Processes \nA. \nExisting Tariff Processes \n20. \nEligible Customers may request Firm Point-To-Point Transmission Service68 or \nNITS.69  Firm Point-To-Point Transmission Service and NITS are available to an Eligible \nCustomer that is willing to pay Congestion Rent associated with its service.70  The \ncharges for transmission services in NYISO (either Firm Point-To-Point Transmission \nService or NITS) include the Transmission Service Charge, Transmission Usage Charge, \nand the NYPA Transmission Adjustment Charge, as applicable.  The Transmission \nService Charge, which is applied to all Actual Energy Withdrawals from the New York \nState (NYS) Power System, will be paid by the transmission customers to transmission \nowners for recovery of the transmission owners’ respective Annual Transmission \nRevenue Requirement.71  The Transmission Usage Charge, which includes Congestion \nRents and charges for Marginal Losses, is paid to NYISO by transmission customers \nscheduling transmission service, including transmission owners scheduling transmission \n \n68 NYISO Tariff, § 3 (Point-To-Point Transmission Service) (4.0.0).  Non-firm \nPoint-To-Point Transmission Service is not available in the markets that the NYISO \nadministers.  Id. § 3.2 (Nature of Non Firm Point to Point Transmission Service) (3.0.0).    \n69 Id. § 4 (Network Integration Transmission Service) (1.0.0).  NYISO does not \noffer the opportunity for transmission customers to make physical reservations for NITS \n(or Firm Point-to-Point Transmission Service), as contemplated in the pro forma OATT.  \nInstead, NYISO offers an alternative form of “financial reservation” based transmission \nservice where NYISO uses locational marginal pricing to manage congestion and operate \nbid-based spot markets.  Transmission customers schedule transmission service implicitly \nwhen they submit spot market energy schedules or arrange for bilateral transactions.  See \nN.Y. Indep. Sys. Operator, 123 FERC ¶ 61,134, at PP 10-11 (2008); N.Y. Indep. Sys. \nOperator, 194 FERC ¶ 61,235, at P 13 (2026) (“With limited exceptions, NYISO does \nnot provide for express, physical reservations of transmission service.  Moreover . . . it \nhas never provided or received a formal request from a transmission customer for \nNITS.”). \n70 NYISO Tariff, §§ 3, 4.  NYISO defines Congestion Rent as:  “The opportunity \ncosts of transmission Constraints on the NYS Transmission System.  Congestion Rents \nare collected by the ISO through its facilitation of LBMP Market Transactions and the \ncollection of Transmission Usage Charges from Bilateral Transactions.”  Id. § 1.3 \n(Definitions - C) (16.0.0).   \n71 Id. § 2.7.2.1; id. § 14.1 (Transmission Service Charge) (32.0.0)."},{"page":19,"startToken":6680,"endToken":7093,"text":"Docket No. EL26-69-000 \n- 19 - \nservice to supply bundled retail customers.72  Any transmission customer purchasing \nfrom the Locational Based Marginal Pricing (LBMP) Market will pay the Congestion \nRent and Marginal Losses charge applicable to its location.73  These Congestion Rent and \nMarginal Losses charges will be included in the calculation of the LBMP charged by \nNYISO for the purchase of energy from the LBMP Market.  For transmission customers \npurchasing energy bilaterally, the Transmission Usage Charge is based on the scheduled \nenergy to be withdrawn.  NYISO also charges transmission customers a NYPA \nTransmission Adjustment Charge, which is applied to all energy transactions, including \nNYS Loads, wheels through, and exports out of NYCA to recover NYPA’s Annual \nTransmission Revenue Requirement for costs recovered through project-specific \ntransmission revenue requirements.74 \n1. \nFirm Point-to-Point Transmission Service \n21. \nNYISO offers a standard Firm Point-to-Point Service Agreement to an Eligible \nCustomer when it submits a completed application for Firm Point-to-Point \nService.75  Firm Point-To-Point Transmission Service does not require NYISO to \nconduct a System Impact Study (SIS) or Transmission Service Study unless:  (1) the \nEligible Customer requests a Transmission Service Study for NYISO to conduct a study \nof facilities that could be constructed;76 or (2) the Eligible Customer is a transmission \n \n72 Id. §§ 2.7.2.2.1, 2.7.2.2.2, 2.7.2.2.3. \n73 Id. § 2.7.2.2.4. \n74 Id. § 14.2 (Transmission Service Charge) (32.0.0), 14.2.2. \n75 Id. § 3.1.4; id. § 7 (Attach. A - Form of Service Agreement for Firm Point-to-\nPoint Service) (1.0.0). \n76 Id. § 3.7 (Additional Study Procedures for Firm Point-to-Point Transmission \nService) (3.0.0), 3.7.1.  An Eligible Customer may request such studies if, for example, \nthe Eligible Customer requesting Firm Transmission Service determines that Congestion \nRent or the cost of Transmission Congestion Contracts (TCC) is too high and the \ncustomer is considering constructing new facilities to create incremental transfer \ncapability resulting in incremental TCCs, or if an Eligible Customer seeks to identify \npossible transmission options to address reliability or other operational concerns).  Id.    \nNYISO defines TCCs as:  “The right to collect or obligation to pay Congestion \nRents in the DayAhead Market for Energy associated with a single MW of transmission \nbetween a specified [point of interconnection] and [point of withdrawal].  TCCs are \nfinancial instruments that enable Energy buyers and sellers to hedge fluctuations in the \nprice of transmission.”  Id. § 1.20 (Definitions - T) (11.0.0)."},{"page":20,"startToken":7093,"endToken":7466,"text":"Docket No. EL26-69-000 \n- 20 - \nowner that proposes a certain type of upgrade or expansion identified in a Local \nTransmission Owner Plan or NYPA transmission plan that is not already subject to the \nTransmission Interconnection Procedures contained in Attachment P of the Tariff, in \nwhich case, the Eligible Customer that is a transmission owner may request an SIS.77  \nThe Transmission Service Study or SIS identifies any additional Direct Assignment \nFacilities78 or Network Upgrades required to comply with an Eligible Customer’s \nrequest.79   \n22. \nIf the Eligible Customer is a transmission owner that requests an SIS, after \ncompletion of that study, NYISO, in cooperation with any transmission owners whose \nfacilities may be modified in performing the upgrade or addition (the affected \ntransmission owner), will conduct a Facilities Study that will include a good faith \nestimate of the cost of any Direct Assignment Facilities and Network Upgrades, and the \nEligible Customer enters into a construction contract with the affected transmission \nowner(s) and provides a letter of credit or security equivalent to the costs of the new \nfacilities or upgrades.80  \n23. \nIf an Eligible Customer requests a Transmission Service Study, after completion \nof the study, the Eligible Customer may pursue construction of the identified \ntransmission upgrades by initiating the Transmission Interconnection Procedures \npursuant to Attachment P of the NYISO Tariff.81  An Eligible Customer may also \nproceed directly to the Transmission Interconnection Procedures in Attachment P \n \n \n \n77 To the extent a transmission owner proposes any other new transmission facility \nor upgrade (i.e., not an upgrade or expansion identified in a Local Transmission Owner \nPlan or NYPA transmission plan), regardless of whether the transmission owner seeks \ncost allocation under the Tariff or proposes a market-based project, the transmission \nowner must submit a Transmission Interconnection Application and proceed under the \nprocedures set forth in Attachment P of the Tariff.  Id. § 3.7. \n78 Direct Assignment Facilities are defined as “[f]acilities or portions of facilities \nthat are constructed by the Transmission Owner(s) for the sole use/benefit of a particular \nTransmission Customer requesting service under the [Tariff].”  Id. § 1.4 (Definitions – D) \n(18.0.0). \n79 Id. § 3.7.3.2.2. \n80 Id. § 3.7.4. \n81 Id. § 3.7.3.2.2."},{"page":21,"startToken":7466,"endToken":7817,"text":"Docket No. EL26-69-000 \n- 21 - \nwithout first requesting a Transmission Service Study.82  Under Attachment P, the \nEligible Customer must submit a Transmission Interconnection Application to NYISO,83 \nwhich then conducts Transmission Interconnection Studies that may consist of short \ncircuit/fault duty, steady state (thermal and voltage), and stability analyses designed to \nidentify the Network Upgrade Facilities84 required for the reliable interconnection of \nTransmission Projects.85  The Eligible Customer may then elect to proceed to an SIS, \nwhich will evaluate the impact of the proposed interconnection on the reliability of the \nNYS Transmission System.86  The Eligible Customer then may request a Facilities Study, \nwhich is used to “update and refine” details such as cost and time estimates for Network \nUpgrade Facilities identified in the SIS.87  Should the Eligible Customer seek to proceed \nwith construction of transmission upgrades, the Network Upgrade Facilities that will be \nconstructed, their construction timeline, the cost of the facilities, and cost allocation for \nthose facilities are memorialized in a Transmission Project Interconnection Agreement. 88   \n2. \nNITS \n24. \nIn order for NYISO to provide NITS to an Eligible Customer, the Eligible \nCustomer must:  (1) submit a completed application; (2) complete certain technical \narrangements with NYISO and the transmission owner; (3) execute a Service Agreement \n \n82 Id.; see also NYISO, Transmission Expansion and Interconnection Manual 23 \n24 (2019), https://www.nyiso.com/documents/20142/7575204/M-23-TEI-Manual-v4.0-\nClean.pdf (NYISO Manual 23). \n83 NYISO Tariff, § 22 (Attachment P - Transmission Interconnection Procedures) \n(12.0.0), 22.4 (Transmission Interconnection Application). \n84 Network Upgrade Facilities are defined, in relevant part, as “the least costly \nconfiguration of commercially available components of electrical equipment that can be \nused . . . to make the modifications or additions to the [NYS] Transmission System that \nare required for the proposed Transmission Project to connect reliably to the system.”   \nId. § 22.1.  \n85 Id. § 22.6.3. \n86 Id. § 22.8.3. \n87 Id. § 22.9.3. \n88 Id. § 22.11.  If a Transmission Developer’s proposed Transmission Project is \nonly interconnecting to its own, existing facilities, a Transmission Project Interconnection \nAgreement is not required.  Id. § 22.11.2."},{"page":22,"startToken":7817,"endToken":8218,"text":"Docket No. EL26-69-000 \n- 22 - \nor request that NYISO file a proposed unexecuted Service Agreement with the \nCommission; and (4) execute a Network Operating Agreement with NYISO.89 \n25. \nRegarding the technical arrangements, NYISO cannot provide NITS until all \nrequired equipment on both sides of the point of delivery or interconnection, as specified \nin the Network Operating Agreement, has been installed.90  The Network Operating \nAgreement contains the terms and conditions to:  (1) operate and maintain equipment \nnecessary for integrating the Network Customer (including communications equipment \nand relaying equipment); (2) transfer data between NYISO, transmission owners, and the \nNetwork Customer; (3) use software programs required for data links and constraint \ndispatching; (4) exchange data on forecasted loads and resources necessary for long-term \nplanning; and (5) address any other technical and operational considerations required for \nNITS.91   \n26. \nNITS requests do not require a NITS Study unless the Eligible Customer \nspecifically requests that NYISO conduct such a study.92  In the event that the Eligible \nCustomer requests a NITS Study, NYISO will coordinate with all affected transmission \nowners in performing the NITS Study, which will identify any Direct Assignment \nFacilities or Network Upgrades necessary to comply with the request.93  The Eligible \nCustomer must also present the final NITS Study for approval to the Operating \nCommittee and Transmission Policy Advisory Subcommittee.  Upon approval of the \nNITS Study, the Eligible Customer may pursue construction of transmission upgrades \n \n89 Id. § 4.2 (Initiating Service) (1.0.0), 4.2.1.  Additionally, Long Island Power \nAuthority must pre-approve any use of its transmission facilities as part of a NITS \nrequest.  Id. § 4.2.1; see id. § 2.5 (Local Furnishing Bonds and Other Tax Exempt \nFinancing) (0.0.0), 2.5.7. \n90 Id. §§ 4.2.3, 4.2.4.  \n91 Id. § 4.8 (Operating Arrangements) (0.0.0), 4.8.2; see id. § 13 (Attachment G – \nNetwork Operating Agreement) (0.0.0). \n92 Id. § 4.5 (Additional Study Procedures For Network Integration Service \nRequests) (3.0.0), 4.5.1.  An Eligible Customer might request such a study, for example, \nif it determines that Congestion Rent or the cost of TCCs is too high and the Eligible \nCustomer is considering constructing new facilities to create incremental transfer \ncapability resulting in incremental TCCs, or if an Eligible Customer requests that \ntransmission facilities be constructed to address reliability or other operational concerns. \n93 Id. § 4.5.3."},{"page":23,"startToken":8218,"endToken":8614,"text":"Docket No. EL26-69-000 \n- 23 - \nthrough the Transmission Interconnection Process.94  Additionally, for new Network \nLoad, the costs of new facilities required to interconnect the new Network Load are \ncharged to the Network Customer.95  \n3. \nLoad Interconnection Process \n27. \nNYISO Tariff Sections 3.9 and 4.5.8 specify additional study procedures for \nPoint-to-Point Transmission Service and NITS, respectively, that apply to Eligible \nCustomers seeking to interconnect new load to the NYS Power System.  NYISO Manual \n23 clarifies that the load interconnection procedures apply to load interconnections that \nare either:  (1) greater than 10 MW connecting at a voltage level of 115 kV or above; or \n(2) 80 MW or more connecting at a voltage level below 115 kV.96  Proposed load \ninterconnections that fall outside these criteria are subject to the procedures of the \napplicable transmission owner.97  NYISO’s primary role in the load interconnection \nprocess is to determine the reliability impacts of any load additions to the NYS Power \nSystem by collaborating with transmission owners on conducting the Load SIS.98   \n28. \nTo start the load interconnection process, an Eligible Customer (or the \ntransmission owner on the Eligible Customer’s behalf) must submit a load \ninterconnection request proposal to NYISO.99  Project details and modeling information \nare required from the customer prior to the start of the Load SIS, including:  (1) the \ncharacteristics of the load project (e.g., data center, cryptocurrency mining); (2) the level \nof flexibility of the load, including if the load would opt to reduce output during peak \nload periods and the load’s willingness to participate in NYISO’s Distributed Energy \nResource program; (3) the load’s daily and seasonal load profile; (4) in-service dates and \naccompanying MW levels; and (5) power flow, dynamics, and short circuit modeling \n \n94 Id. §§ 22.8, 22.9, 22.11. \n95 Id. § 4.4 (Designation of Network Load) (0.0.0), 4.4.2 (“The costs of new \nfacilities required to interconnect a new Network Load shall be determined in accordance \nwith the procedures provided in Section 4.5 and shall be charged to the Network \nCustomer in accordance with Commission policies.”). \n96 NYISO Manual 23, § 3.5.   \n97 NYISO Technical Bulletin No. 266 at 1. \n98 Id.  \n99 NYISO Tariff, § 3.9 (Study Procedures for New Load or Facility \nInterconnections to the NYS Power System) (3.0.0), 3.9.1; NYISO Manual 23, § 3.5."},{"page":24,"startToken":8614,"endToken":9015,"text":"Docket No. EL26-69-000 \n- 24 - \ndata.100  After the Eligible Customer executes a System Impact Study Agreement with the \ntransmission owner whose system the Eligible Customer proposes to interconnect \n(Connecting Transmission Owner) and submits a $150,000 study deposit, NYISO, in \ncooperation with the Connecting Transmission Owner, will then perform technical \nstudies as part of the Load SIS that evaluates certain criteria.101   \n29. \nIf the Load SIS indicates adverse reliability impacts, NYISO and the Connecting \nTransmission Owner will identify alternatives to eliminate the impact, which may include \npotential (non-binding) Network Upgrades or changes to the project.102  If NYISO \ndetermines through the Load SIS that the proposed load will impact affected transmission \nowners or Affected Systems, those parties may review project information, including the \nstudy base cases.103  NYISO’s role in the load interconnection process concludes after \nperforming the Load SIS; NYISO is not a party to interconnection agreements for load \ninterconnections.104  Upon approval of the final Load SIS study report and payment to \nNYISO and the Connecting Transmission Owner for the cost of the study, the Eligible \nCustomer may then enter into a Facilities Study Agreement and an interconnection \nagreement with the Connecting Transmission Owner.105  The Facilities Study will further \nevaluate and provide non-binding, good-faith cost estimates for any Network Upgrades \nidentified in the Load SIS.106  The final costs, cost allocation, and construction schedule \nfor the Network Upgrades identified in the load interconnection process are memorialized \n \n100 NYISO Technical Bulletin No. 266 at 2. \n101 NYISO Tariff, § 3.9.2; see NYISO Technical Bulletin No. 266 at 1.  The \ncriteria include:  (1) potential significant impacts of the proposed interconnection on \nsystem reliability; (2) potential impacts on system voltage, stability, and thermal \nlimitations per NYISO’s Reliability Rules; (3) whether the interconnection would require \nmodifying the NYS Power System to maintain Interface transfer capability or to comply \nwith reliability requirements; (4) an evaluation of alternatives that would eliminate any \nadverse reliability impacts; and (5) an estimate of the increase or decrease in Total \nTransfer Capability.  NYISO Tariff, § 3.9.2.    \n102 NYISO Technical Bulletin No. 266 at 3.  Additionally, consideration will be \ngiven to load ramp-up schedules to determine if adverse reliability impacts arise prior to \nthe project reaching its full requested load.   \n103 Id. at 1. \n104 Id. \n105 Id. at 1, 3; see also NYISO Tariff, § 3.9.4.  \n106 NYISO Technical Bulletin No. 266 at 3."},{"page":25,"startToken":9015,"endToken":9351,"text":"Docket No. EL26-69-000 \n- 25 - \nin the interconnection agreement between the transmission owner and the Eligible \nCustomer.107   \n4. \nLocal Transmission Planning Process \n30. \nWith respect to local transmission planning, transmission owners evaluate \nsolutions to identified transmission needs, including transmission solutions proposed by \nmarket participants and other parties, for inclusion in their Local Transmission Plans.108  \nEach planning cycle, each transmission owner submits the finalized portions of its current \nLocal Transmission Plan to NYISO for inclusion in the Reliability Needs Assessment.109  \nNYISO then evaluates transmission owners’ Local Transmission Plans in relation to \nregional and local transmission needs.110  NYISO reports the results of its evaluation \nsolely for informational purposes in the relevant NYISO planning report prepared under \nAttachment Y, and the transmission owners are not required to revise their Local \nTransmission Plans based on the results of NYISO’s evaluation.   \n5. \nGenerator Interconnection \n31. \nNYISO processes generator interconnection requests under Attachment HH of its \nTariff.111  NYISO administers a single, two-phase cluster study process that assesses the \nlocal impacts of proposed interconnections in the first phase and the broader systemwide \nimpacts of the proposed interconnection in the second phase.  Specifically, in Phase 1 of \nits study process, Connecting Transmission Owners and Affected Transmission Owners \nassess the local impacts of the proposed interconnections of the cluster study projects to \nidentify the Connecting Transmission Owner’s attachment facilities, distribution \nupgrades, and local system upgrade facilities and provide cost estimates to construct the \nfacilities.112  In Phase 2, NYISO performs a cluster study to identify the system upgrade \nfacilities and distribution upgrades required for the reliable interconnection of cluster \n \n \n \n107 Id.; NYISO Tariff, § 3.9.4; NYISO November 21 ANOPR Comments at 2. \n108 NYISO Tariff, § 31.2.1.1.2.3.  \n109 Id. § 31.2.1.2.5. \n110 Id. § 31.2.1.3. \n111 Id., attach. HH (Standard Interconnection Procedures) (1.0.0). \n112 Id. attach. HH, § 40.10 (Phase 1 Study Process, Development of System \nModels, and Phase 2 Entry Decision Period) (1.0.0), 40.10.4."},{"page":26,"startToken":9351,"endToken":9708,"text":"Docket No. EL26-69-000 \n- 26 - \nstudy projects to the transmission system or distribution system.113  For projects \nrequesting capacity resource interconnection service (CRIS), NYISO also conducts a \ncluster study deliverability study to assess their requested CRIS and identify any required \nsystem deliverability upgrades.114  The Connecting Transmission Owner, Affected \nTransmission Owner, or Affected System Operator then determines the cost estimates for \nand a preliminary schedule to construct the identified upgrade facilities and updates, as \nneeded, the identification and cost estimates of the upgrade facilities identified in the \nPhase 1 Study.115   \n32. \nPursuant to the Tariff, an interconnection customer may request, and NYISO may \nprovide, provisional interconnection service for limited operation prior to the completion \nof the cluster study and prior to completion of requisite attachment facilities, distribution \nupgrades, system upgrade facilities, system distribution upgrades, or system protection \nfacilities.116  In evaluating a request for provisional interconnection service, NYISO, in \nconjunction with the Connecting Transmission Owner(s), shall determine, through \navailable studies or additional studies as necessary, “whether stability, short circuit, \nthermal, and/or voltage issues would arise if the Interconnection Customer interconnects \nwithout modifications to the facility or the New York State Transmission System (or \ndistribution system as applicable).”117  NYISO does not offer surplus interconnection \nservice under its Tariff. \n6. \nCo-Located Load Interconnection Process \n33. \nNYISO does not have a process in place to evaluate large load co-located with \ngenerating facilities.118  Generator interconnection requests proceed through NYISO’s \n \n113 Id. attach. HH, § 40.11 (Phase 2 Study) (0.0.0).  NYISO’s Phase 2 cluster study \nanalysis encompasses both the system impact and facilities studies and therefore NYISO \ndoes not have a separate facilities study. \n114 Id. attach. HH, §§ 40.11 (Phase 2 Study), 40.11.3; see also id. § 40.13 \n(Deliverability Studies and Cost Allocation Methodology for CRIS) (1.0.0). \n115 Id. attach. HH, § 40.11.4. \n116 Id. attach. HH, § 40.22 (Construction of Connecting Transmission Owner’s \nAttachment Facilities, System Upgrade Facilities, and System Deliverability Upgrade) \n(0.0.0.), 40.22.3. \n117 Id. \n118 NYISO’s Tariff contains market participation provisions for Co-Located \nStorage Resources, but the definition of Co-Located Storage Resources excludes"},{"page":27,"startToken":9708,"endToken":10083,"text":"Docket No. EL26-69-000 \n- 27 - \nCluster Study Process, where they are studied as a group by evaluating their cumulative \nimpact on the transmission system, identifying the upgrades required to mitigate the \ncollective impact of the group of projects, and allocating the costs of such upgrades \namong the projects contributing to the need for such upgrades.119  The Cluster Study \nProcess and the load interconnection process are distinct and separate processes for \nevaluating projects’ impacts on the reliability of the transmission system.  \n34. \nNYISO’s current Behind-the-Meter Net Generation Resource participation model \nallows generation that routinely serves a Host Load to offer any excess generation into \nNYISO’s wholesale markets.120  As noted above, all transmission services are subject to \nthe Transmission Service Charge, which is applied to all Actual Energy Withdrawals \nfrom the NYS Power System. \nB. \nRecent Stakeholder Proceedings in NYISO \n35. \nGiven the growth of large and co-located loads, NYISO has begun considering \nrevisions and enhancements to the Tariff.  As referenced above, NYISO recently adopted \nTechnical Bulletin No. 266 to enhance and clarify its existing load interconnection study \nprocess, and NYISO explains in response to the ANOPR that it has begun a stakeholder \nprocess to revise its large load interconnection study process.121  NYISO asserts that it \nplans to introduce reforms that address bulk-system reliability concerns while improving \nthe efficiency and predictability of the large load interconnection process and aims to file \ncorresponding tariff revisions with the Commission by December 2026.122   \n36. \nNYISO has also begun other large load-related project initiatives for 2026.   \nThe first will focus on incentivizing large loads to participate in NYISO’s markets as \nflexible resources via enhancements to NYISO’s existing Distributed Energy Resource \n \n \n \ngenerators that are co-located with load.  See id. § 1.3 (Definitions – C) (16.0.0) \n(definition of Co-Located Storage Resource).  \n119 See N.Y. Indep. Sys. Operator, Inc., 191 FERC ¶ 61,049 (2025). \n120 See NYISO, NYISO Tariffs, Market Administration and Control Area Services \nTariff, § 2.8 (Definitions – H) (3.0.0) (definition of Host Load) (NYISO MST).  \n121 NYISO November 21 ANOPR Comments at 3 & n.7 (stating that its 2026 \nstakeholder process will prioritize “(1) Flexible Load models for Large Loads and (2) \nReliability Planning and Large Load Integration.”). \n122 NYISO Challenges and Considerations at 22."},{"page":28,"startToken":10083,"endToken":10474,"text":"Docket No. EL26-69-000 \n- 28 - \nand Behind-the-Meter Net Generation programs.123  NYISO explains that its current \nBehind-the-Meter Net Generation Resource participation is premised on a firm Host \nLoad that does not participate in wholesale markets and is not easily controllable or \nresponsive to market signals, noting that an expansion of the participation model to \naccommodate flexible Host Loads could contribute additional surplus supply to \nwholesale markets.124  As part of this initiative, NYISO plans to discuss a general \nframework for enhanced co-located load plus generation participation options. 125  NYISO \nexpects that tariff revisions related to co-located load would not be filed until 2027.126   \n37. \nWhile we are encouraged by NYISO’s stakeholder efforts, and by its initial \nattention to the pressing concerns associated with large and co-located loads127 and to the \nSecretary’s interest in these issues,128 we are initiating this FPA section 206 proceeding \nin order to ensure that NYISO’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 NYISO promptly proposes \nrevisions to ensure that its Tariff remains just and reasonable. \n \n123 NYISO, Flexible Load Models – Large Loads (Feb. 24, 2026), \nhttps://www.nyiso.com/documents/20142/57218179/flexible%20large%20loads%200224\n26%20icap.pdf (NYISO Flexible Load Models); NYISO 2025-2034 Comprehensive \nReliability Plan. \n124 NYISO 2025-2034 Comprehensive Reliability Plan at 77-78. \n125 NYISO Flexible Load Models at 14. \n126 Id. at 5. \n127 See NYISO, 2024 Reliability Needs Assessment (RNA) 34-37 (Nov. 19, 2024), \nhttps://www.nyiso.com/documents/20142/2248793/2024-RNA-Report.pdf (noting a \ndramatic increase “over the past several years” in load interconnection requests and that \nthe increasing speed and scale with which large loads seek to interconnect in NYISO will \nhave “major impacts on future load growth and system risk”); Transcript, Large Loads \nCo-Located at Generating Facilities Technical Conference, Docket No. AD24-11-000, at \n63-64 (Nov. 1, 2024) (Zachary G. Smith, Senior Vice President of System and Resources \nPlanning, NYISO) (stating that the load interconnection provisions in NYISO’s Tariff \n“gives no clarity at all in terms of responsibility for facilities that are needed to \ninterconnect those loads, [or for] cost responsibility,” which creates confusion between \nutilities).  \n128 See supra PP 6-7."},{"page":29,"startToken":10474,"endToken":10814,"text":"Docket No. EL26-69-000 \n- 29 - \nIII. \nDiscussion \n38. \nBased on the discussion below, pursuant section 206 of the FPA, we direct NYISO \nand the Transmission Owners, within 60 days of the date of this order, to either:   \n(1) show cause as to why the Tariff remains just and reasonable and not unduly \ndiscriminatory or preferential without provisions addressing:   \n(a) the application process, study procedures, and ongoing operational \nrequirements that apply to Eligible Customers seeking transmission service \non behalf of large loads;  \n(b) additional transparency concerning the Network Upgrade costs to \nprovide transmission service to Eligible Customers on behalf of large loads, \na pro forma cost recovery agreement between NYISO, 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 \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.   \n39. \nWe also direct NYISO to submit, within 30 days of the date of issuance of this \norder, an informational report on how NYISO intends to ensure that adequate generation \nwill be available to serve existing and new large loads.   \n40. \nInterested entities may respond within 30 days of NYISO’s and the Transmission \nOwners’ filings, addressing either or both of:  (1) whether the existing Tariff remains just"},{"page":30,"startToken":10814,"endToken":11311,"text":"Docket No. EL26-69-000 \n- 30 - \nand reasonable and not unduly discriminatory or preferential; and (2) if not, what changes \nto the Tariff should be implemented as replacement rates.   \n41. \nWe recognize that NYISO and/or the Transmission Owners, (to the extent the \nmatters addressed herein implicate aspects of the Tariff over which they have the filing \nrights) may elect to address some or all of the issues discussed in this order by proposing \nrevisions to the Tariff pursuant to their applicable FPA section 205 filing rights.  We \nstrongly encourage this.  Although both the Secretary’s ANOPR and our own Order \nRegarding Intent to Act expressly recognized (and indeed encouraged) that possibility,129 \nno such filings were received from NYISO by the Commission prior to the issuance of \nthis order.  Should NYISO and/or the Transmission Owners elect to make such filings in \nresponse to this order, those filings should state explicitly that the proposals are being \nsubmitted under FPA section 205.  Should NYISO and/or the Transmission Owners \nsubmit a filing under FPA section 205, they should also explain which of the \nCommission’s above directives their filing addresses and how it resolves them.  \nAdditionally, any such filing should provide a reasoned explanation for how the proposal \nwill avoid disrupting existing commercial arrangements and clearly identify a reasonable \neffective date that accommodates such existing commercial arrangements. \n42. \nThe Commission will consider requests from NYISO and/or the Transmission \nOwners to hold, for up to 90 days, all or certain aspects of this FPA section 206 \nproceeding in abeyance, including the deadline to respond to this order.  Any such \nabeyance, which will begin as of the deadline to respond to this order, would be \nconsidered to provide NYISO and the Transmission Owners time while they work \nthrough the stakeholder processes to develop FPA section 205 filings to revise the Tariff \nto address the issues raised in this order.  Requests for a full or partial abeyance130 should \nbe submitted prior to the deadline to respond to this order, specifically within 45 days of \nissuance of this order, to allow time for the Commission to act on the abeyance request.  \nWe emphasize that we will not grant such abeyances reflexively, that any abeyance will \nbe limited to 90 days, and that we will look with great disfavor toward requests to extend \nthe abeyance period.  We anticipate that successful abeyance requests, if any, will include \nboth (1) a robust description of the content of a potential future filing under FPA section \n205 and (2) a reasoned and specific explanation of when such a filing is expected to be \nmade. \n \n129 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5. \n130 A partial abeyance may be appropriate to the extent NYISO 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."},{"page":31,"startToken":11311,"endToken":11755,"text":"Docket No. EL26-69-000 \n- 31 - \n43. \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.131  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 \n44. \nWe today make a preliminary finding that NYISO’s Tariff appears to be unjust \nand unreasonable because it lacks provisions that address, with sufficient clarity and \nconsistency, how NYISO and/or the Transmission Owners will timely study (i.e., within \n60-90 days of receiving the request) the provision of transmission service to Eligible \nCustomers on behalf of large loads.132   \n45. \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.    \n46. \nWe recognize that NYISO’s Tariff includes certain transmission and load \ninterconnection studies.  However, as noted above, with respect to transmission service \nrequests, NYISO will only conduct an SIS, Transmission Service Study, or NITS Study  \nif the Eligible Customer requests such a study or if the Eligible Customer chooses to \nproceed under the Transmission Interconnection Procedures in Attachment P of the \n \n131 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). \n132 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":32,"startToken":11755,"endToken":12136,"text":"Docket No. EL26-69-000 \n- 32 - \nNYISO Tariff.133  Furthermore, although the Tariff contains the basic procedures for \nNYISO’s Load SIS process for new load interconnection, greater detail and significant \nrequirements pertaining to this process are housed in non-Tariff documents, including \ninformation requirements, study deposits, and study assumptions and procedures.134   \nIn addition, as NYISO has already noted, facilities study procedures vary among the \ntransmission owners.135  We therefore are concerned that the Tariff is unjust and \nunreasonable because it lacks provisions that address, with sufficient clarity and \nconsistency, the study process for the provision of transmission service to Eligible \nCustomers on behalf of large loads. \n47. \nWe direct NYISO and the Transmission Owners, to the extent the matters \naddressed herein implicate aspects of the Tariff over which they have the filing rights, to \nexplain whether the Tariff remains just and reasonable without an application process, \nstudy 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.  We recognize that \nNYISO is currently considering potential reforms to enhance its processes related to large \nload additions in its stakeholder process and we encourage NYISO to consider whether \nthese efforts would, either fully or in part, address the Commission’s concerns that the \nTariff appears to be unjust and unreasonable.   \n1. \nJurisdiction \n48. \nAt the outset, we clarify the principles relating to the Commission’s jurisdiction \nover the matters relevant to the integration of large loads onto the transmission system \nand the impacts of large loads on the transmission system.  We recognize that rates, \nterms, and conditions associated with the addition of and service to large loads implicate \nboth federal and state interests.  We also recognize that resolution of issues related to \nlarge load additions will require the involvement of both federal and state actors, \nincluding the Commission, state public utility commissions, and other state and local \nentities.  We are encouraged by efforts made at the state level to address issues related to \nlarge load additions that fall within state jurisdiction.136 \n \n133 See supra PP 21-26.  \n134 See supra PP 27-29. \n135 See supra P 9. \n136 See generally NARUC April 14 ANOPR Comments (highlighting action taken \nby state public utility commissions related to large loads)."},{"page":33,"startToken":12136,"endToken":12565,"text":"Docket No. EL26-69-000 \n- 33 - \n49. \n  As discussed below, however, certain aspects of the process for integrating large \nloads onto the transmission system fall squarely within the Commission’s exclusive \njurisdiction.   \n50. \nSpecifically, we find that it is within the Commission’s exclusive authority to \nensure 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.137 \n51. \nThe Commission is a creature of statute and has jurisdiction over only those \nmatters that Congress has given it the authority to regulate.138  That authority includes \njurisdiction over the wholesale sale and transmission of electricity in interstate \ncommerce, including all facilities used for such sale and transmission.139  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.140  \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.141  As part of its transmission authority, the \nCommission has exercised jurisdiction over the terms of certain interconnections to the \n \n137 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 NYISO Tariff, § 1.5 (Definitions – E) (16.0.0). \n138 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). \n139 16 U.S.C. § 824(b)(1). \n140 Id. §§ 824d, 824e; see FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 278 \n(2016) (EPSA) (approving “a common-sense construction of the FPA’s language, \nlimiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the \nwholesale rate’” (cleaned up)).    \n141 New York v. FERC, 535 U.S. 1, 17, 19-20 (2002) (upholding the Commission’s \nexercise of jurisdiction over unbundled retail transmission service)."},{"page":34,"startToken":12565,"endToken":13014,"text":"Docket No. EL26-69-000 \n- 34 - \ntransmission system as an element of transmission service,142 including the \ninterconnection of wholesale load to the transmission system.143  \n52. \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 \nEligible Customers on behalf of large loads, the costs of which are included in \ntransmission rates.  As such, this study process directly affects Commission-jurisdictional \ntransmission rates.144  The Commission has exclusive authority to ensure that the process \nto study the provision of transmission service to Eligible Customers is just and reasonable \nand not unduly discriminatory or preferential.  We therefore find that we have authority \nto ensure that tariffs include provisions that clearly and consistently address the study \nprocess for the provision of transmission service to Eligible Customers on behalf of large \nloads, including the unique impacts that providing transmission service to Eligible \nCustomers on behalf of large loads may have on the transmission system. \n53. \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 \n \n142 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). \n143 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). \n144 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":35,"startToken":13014,"endToken":13469,"text":"Docket No. EL26-69-000 \n- 35 - \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.145  As such, we recognize that states will continue to regulate:  \n(1) the specific terms of retail sales to large load;146 (2) which entities may make retail \nsales within their borders, including which entities are legally permitted to provide \nelectricity to retail large load customers;147 and (3) any siting decisions and construction \nassociated with the large load project.148  Nothing in this order is intended to intrude upon \nstate authority over retail service to large loads.   \n54. \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 \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 NYISO’s Tariff appears to be unjust \nand unreasonable or unduly discriminatory or preferential because it lacks sufficiently \nclear and consistent provisions regarding the study process related to the provision of \ntransmission service to Eligible Customers on behalf of large loads.  We need not \ncomprehensively address the Commission’s jurisdiction over other aspects of the addition \nof large loads to the transmission system at this time.  \n2. \nTariff Provisions \n55. \nIn the following section, we begin by considering NYISO’s Tariff as it relates to \nhow NYISO and/or the Transmission Owners will study the provision of transmission \nservice to Eligible Customers on behalf of large loads and explain our concerns that the \nlack of sufficiently clear and consistent provisions regarding the study process for the \nprovision of transmission service to Eligible Customers on behalf of large loads is unjust \n \n145 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th \n1107, 1129 (6th Cir. 2025). \n146 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). \n147 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69. \n148 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":36,"startToken":13469,"endToken":13916,"text":"Docket No. EL26-69-000 \n- 36 - \nand unreasonable or unduly discriminatory or preferential.  We then consider whether the \nTariff is unjust and unreasonable without certain elements.  First, we consider whether \nthe Tariff lacks sufficiently clear and consistent Tariff provisions establishing an \nappropriate definition of large load, as a separate category of load.  Second, we consider \nwhether the Tariff lacks sufficiently clear and consistent Tariff provisions establishing an \napplication process and requirements for Eligible Customers requesting transmission \nservice on behalf of large loads and a study process that considers the unique operational \nchallenges of providing transmission service to Eligible Customers on behalf of large \nloads.  Third, we consider whether the Tariff lacks sufficiently clear and consistent Tariff \nprovisions establishing ongoing operational requirements necessary to ensure that \nNYISO can reliably provide transmission service given the unique operational impacts on \nthe transmission system of providing transmission service to Eligible Customers on \nbehalf of large loads.  Finally, we consider whether the Tariff requires such ongoing \noperational requirements for Eligible Customers taking transmission service on behalf of \nlarge loads to be memorialized in service agreements. \n56. \nWe preliminarily find that NYISO’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 NYISO and/or the Transmission Owners will \nstudy the provision of transmission service to Eligible Customers on behalf of large \nloads.  We recognize that NYISO and/or the Transmission Owners may have existing \nload integration processes, including studies that may be performed in evaluating the \nprovision of transmission service to Eligible Customers on behalf of large loads.149  \nHowever, we are concerned that those processes and any required studies with regard to \nthe provision of transmission service are not described in the Tariff with the degree of \nclarity and specificity necessary to ensure that the transmission provider can mitigate \noperational risks of providing transmission service to Eligible Customers on behalf of \nlarge loads, given their impact on the transmission system, avoid disputes regarding how \nstudies are conducted, deter speculative or duplicative requests for transmission service \nby Eligible Customers on behalf of large loads, and help avoid excessive and unnecessary \nNetwork Upgrades.   \n57. \nMoreover, we are concerned that the existing Tariff does not contain other \nelements akin to those described below, which we preliminarily find may be necessary to \nensure that the rates, terms, and conditions of jurisdictional transmission service are just \nand reasonable.   \n58. \nAt the outset, we recognize that the Transmission Owners may be partially \nresponsible for conducting the studies that (1) evaluate whether a large load may be \ninterconnected to the transmission system and served by the Eligible Customer and (2) \n \n149 See supra PP 21-29."},{"page":37,"startToken":13916,"endToken":14319,"text":"Docket No. EL26-69-000 \n- 37 - \ndetermine whether Network Upgrades are necessary to provide transmission service.  We \nappreciate that this role may stem from how NYISO and the Transmission Owners \nallocated rights and responsibilities in the governing documents establishing NYISO.  We \ndo not seek to alter that allocation of rights and responsibilities. \n59. \nWe are nonetheless concerned that NYISO’s Tariff lacks a mandatory study \nprocess that addresses the unique operational and reliability challenges that providing \ntransmission service to Eligible Customers on behalf of large loads presents to the \ntransmission system.  Large loads can be more energy intensive and geographically \nconcentrated than traditional load, and exhibit different load profiles and operational \ncharacteristics.150  NYISO itself, along with other stakeholders in New York, has \nrecognized that large loads can have a disproportionate impact on system reliability due \nto their size and unique characteristics, and so too has NYISO acknowledged that the \nscale, pace, and characteristics of large load growth present significant operational and \nplanning challenges.151  As a result, providing transmission service to Eligible Customers \non behalf of large loads may be more complex and could raise greater reliability concerns \nfor the transmission system, relative to a situation where Eligible Customers seek \ntransmission service on behalf of traditional load.   \n60. \nWithout a clear and consistent process to study the provision of transmission \nservice to Eligible Customers on behalf of large loads, NYISO and/or the Transmission \nOwners may not fully capture the transmission system impacts of providing such \ntransmission service, which could result in significant operational risks for the \ntransmission system.  Furthermore, we are concerned that, without sufficiently clear and \nconsistent Tariff provisions, NYISO will not have the ongoing visibility and operational \ncontrol necessary to provide reliable transmission service. \n61. \nWe are also concerned that the absence of sufficiently clear and consistent Tariff \nprovisions for how NYISO and/or the Transmission Owners will study the provision of \ntransmission service to Eligible Customers on behalf of large loads will lead to disputes \n \n \n150 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). \n151 See NYISO November 21 ANOPR Comments at 7-8; NYISO Challenges and \nConsiderations at 5; see also NY State Reliability Council November 21 ANOPR \nComments at 3; NYTOs November 21 ANOPR Comments at 20."},{"page":38,"startToken":14319,"endToken":14777,"text":"Docket No. EL26-69-000 \n- 38 - \nover a variety of issues—e.g., study timelines and delays,152 how the transmission service \nneeded on behalf of the large load is studied,153 what types of Network Upgrades are \nconsidered and how required Network Upgrades to provide the requested transmission \nservice are determined.154  Such disputes may arise from the lack of transparency in how \nstudies are performed and how decisions will be made.155  We are thus concerned that the \n \n152 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; National Grid November 21 \nANOPR Comments at 7 (asserting that the absence of standardized rules relating to large \nload integration can cause “inefficiencies, increased project timelines, and difficulties \ndeveloping cost estimates”); NYTOs November 21 ANOPR Comments at 11-12 (noting \nrecent efforts by transmission owners, the New York Commission, and NYISO to \nimprove the load interconnection process to shorten study timelines); ODEC December 5 \nANOPR Comments at 4. \n153 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; National Grid November 21 ANOPR Comments \nat 19-20. \n154 Specifically, commenters raised concern that transmission providers/owners \nmay only consider traditional transmission infrastructure or that there is a lack of \nconsideration of alternative transmission solutions.  See, e.g., ACORE November 21 \nANOPR Comments at 3-4, 6-7; American Terawatt November 21 ANOPR Comments 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. \n155 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"},{"page":39,"startToken":14777,"endToken":15235,"text":"Docket No. EL26-69-000 \n- 39 - \nlack of clear and consistent provisions in NYISO’s Tariff related to the study process for \nthe provision of transmission service to Eligible Customers on behalf of large loads \nappears to be unjust and unreasonable or unduly discriminatory or preferential.   \n62. \nLastly, we are concerned that NYISO’s existing Tariff fails to deter speculative or \nduplicative requests for transmission service by Eligible Customers on behalf of large \nloads.  Many ANOPR comments assert that clear and consistent provisions establishing \nstudy timelines and costs, readiness requirements, and/or penalties will deter speculative \nor duplicative requests related to large load additions.156  Commenters explain that \nspeculative requests may bog down and delay the study process, wasting time and \nresources for transmission providers;157 result in inaccurate study results or delays for \nother Eligible Customers seeking transmission service on behalf of load;158 create a \nsubstantial risk of cost shifts if the large load additions do not materialize as planned;159 \n \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. \n156 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; NY UIU \nNovember 21 ANOPR Comments at 5; NYISO November 21 ANOPR Comments at 3 \n(noting the Technical Bulletin No. 266’s inclusion of load interconnection study deposits \nand timelines); NYTOs November 21 ANOPR Comments at 20 (asserting that \nwithdrawals of large loads from the transmission system can negatively impact market \nefficiency and reliability); Ohio FEA November 21 ANOPR Comments at 4. \n157 See, e.g., Eolian November 21 ANOPR Comments at 17-18; GridCare \nDecember 5 ANOPR Comments at 5; Illinois AG November 21 ANOPR Comments at 9-\n10; Institute for Progress November 21 ANOPR Comments at 9; Ohio FEA November 21 \nANOPR Comments at 4; Vistra November 21 ANOPR Comments at 23. \n158 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 14-\n15. \n159 See, e.g., Buckeye November 21 ANOPR Comments at 1-2; Exelon November \n21 ANOPR Comments at 3; NRECA November 21 ANOPR Comments at 9; OCC \nNovember 21 ANOPR Comments at 9; Southeast PIOs November 21 ANOPR"},{"page":40,"startToken":15235,"endToken":15596,"text":"Docket No. EL26-69-000 \n- 40 - \nand distort load forecasts.160  Clear and consistent study procedures that include readiness \nrequirements (i.e. meaningful milestones and/or financial commitments) can help ensure \nthat Eligible Customers’ requests for transmission service on behalf of large loads are \nmore viable and more likely to materialize as planned, given that they must meet specific \nmilestones and/or pay costs to proceed.   \n63. \nMore specifically, we preliminarily find that NYISO’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(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 customers161 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 \nComments at 20; State Entities November 21 ANOPR Comments at 7-8; TAPS \nNovember 21 ANOPR Comments at 15, 22-24; Tri-State November 21 ANOPR \nComments at 6, 8; Vistra November 21 ANOPR Comments at 23; see also NY UIU \nNovember 21 ANOPR Comments at 2-3, 9-10. \n160 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; \nNY UIU November 21 ANOPR Comments at 7-8; OCC November 21 ANOPR \nComments at 9; PIOs November 21 ANOPR Comments at 5; Southeast PIOs November \n21 ANOPR Comments at 41; Talen November 21 ANOPR Comments at 9. \n161 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."},{"page":41,"startToken":15596,"endToken":16085,"text":"Docket No. EL26-69-000 \n- 41 - \n64. \nFirst, we preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable because it lacks a definition of large load, as a new category of load.  \nCurrently, NYISO has load interconnection procedures that apply to load interconnection \nrequests for projects that are greater than 10 MW connecting at a voltage level of 115 kV \nor above, or projects 80 MW or more connecting at a voltage level below 115 kV.  \nHowever, these procedures are only partially in NYISO’s Tariff.  As NYISO \nacknowledges, integrating large loads poses specific challenges to transmission system \noperation given their size, operational behavior, and unique potential to impact the \ntransmission system.162  An appropriate definition, including a load size and \ninterconnection voltage threshold, should be based on the characteristics of NYISO’s \ntransmission system. That said, based on the record in the ANOPR proceeding,163 it \nappears that it would be reasonable to define a large load as a new commercial or \nindustrial customer, located at a single site behind one or more points of interconnection, \nand that has a peak load of 50 MW or greater and interconnects to the transmission \nsystem at a voltage level of greater than 69 kV, and is not part of a co-location \narrangement.  In its response to this order, NYISO should explain whether the Tariff \nremains just and reasonable without such a definition or propose Tariff revisions \nestablishing its own definition of large load. \n65. \nSecond, we preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable because it lacks sufficiently clear and consistent provisions establishing the \napplication process and study procedures that will be used when NYISO and/or the \nTransmission Owners evaluate the provision of transmission service to Eligible \nCustomers on behalf of large loads.164  NYISO should explain whether the Tariff remains \njust and reasonable, for example, without: (1) an application process that accepts Eligible \nCustomers’ applications for transmission service on behalf of large loads on a rolling \n \n162 NYISO November 21 ANOPR Comments at 2.  \n163 See, e.g., Constellation November 21 ANOPR Comments at 13 (supporting a \nvoltage threshold); DTE November 21 ANOPR Comments at 3, 17-19 (recommending a \nthreshold of an amount between 50 MW to 100 MW); Eolian November 21 ANOPR \nComments at 8-9 (recommending a voltage threshold greater than or equal to an amount \nbetween 60 kV to 100 kV); Illinois AG November 21 ANOPR Comments at 7 \n(supporting a 20 MW or 50 MW threshold and consideration of other factors, such as \nvoltage level); ITC November 21 ANOPR Comments at 3 (recommending a threshold of \nbetween 50 MW to 100 MW); Nebraska Board November 21 ANOPR Comments at 4 \n(proposing a 50 MW threshold); National Grid November 21 ANOPR Comments at 11 \n(asserting appropriate thresholds of 50 or 80 MW depending on the region); New Mexico \nCommission November 21 ANOPR Comments at 5 (proposing a 50 MW threshold). \n164 See supra P 46."},{"page":42,"startToken":16085,"endToken":16521,"text":"Docket No. EL26-69-000 \n- 42 - \nbasis, (2) a non-refundable application fee, and sufficient readiness requirements that \nescalate at distinct phases of the study process to deter duplicative or speculative requests \nfor transmission service (e.g. meaningful milestones and/or financial commitments); and \n(3) information and data requirements that Eligible Customers must submit to NYISO \nand/or the Transmission Owners regarding the characteristics of the large load on behalf \nof which the Eligible Customer is taking transmission service, including disclosure to \nNYISO of any substantially similar pending transmission service requests on behalf of \nthe same large load customer.165  NYISO may also elect to propose Tariff revisions \nestablishing such an application process, fee, and requirements.   \n66. \nFurther, NYISO’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 NYISO’s Tariff may not clearly and consistently require NYISO or \nthe Transmission Owners to conduct studies that evaluate the transmission system’s \nability to withstand risks observed from analyzed large load behavior created by the large \nload at the point of interconnection, or any other necessary supplemental studies to \nevaluate the impact of providing transmission service to Eligible Customers on behalf of \nlarge loads.166  Additionally, we preliminarily find that NYISO’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.167  Additionally, we note that \n \n165 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). \n166 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). \n167 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."},{"page":43,"startToken":16521,"endToken":16893,"text":"Docket No. EL26-69-000 \n- 43 - \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.168 \n67. \nAdditionally, we preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable because it lacks clear and consistent provisions requiring the evaluation of \nalternative transmission technologies169 as potential solutions to accommodate an \nEligible Customer’s request for transmission service on behalf of a large load.  \nAlternative transmission technologies can add more capacity on existing transmission \nlines quickly, often within one to three years.170  Unlike with traditional load growth,171 \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 \n \n168 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. \n169 For purposes of this order, alternative transmission technologies include static \nsynchronous compensators, static VAR compensators, advanced power flow control \ndevices, transmission switching, synchronous condensers, voltage source converters, \nadvanced conductors, tower lifting, and dynamic line ratings.  We note that the \nCommission has also referred to these types of technologies as Grid Enhancing \nTechnologies (GET). \n170 WATT and Advancing Modern Powerlines November 21 ANOPR Comments \nat 5-6. \n171 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.”)."},{"page":44,"startToken":16893,"endToken":17340,"text":"Docket No. EL26-69-000 \n- 44 - \nloads.172  The Commission has previously recognized that alternative transmission \ntechnologies have the potential to mitigate or defer the need for traditional Network \nUpgrades and often can be deployed both more quickly and at lower cost than traditional \nNetwork Upgrades, and therefore failing to consider whether alternative transmission \ntechnologies can meet transmission needs more efficiently or cost-effectively than \ntraditional Network Upgrades has the potential to render Commission-jurisdictional rates \nunjust and unreasonable.173  Further, to the extent Network Upgrade costs to \naccommodate an Eligible Customer’s request for transmission service on behalf of a large \nload are rolled into a transmission owner’s transmission revenue requirement, \ntransmission customers other than the Eligible Customer may bear a portion of those \nNetwork Upgrade costs, highlighting the need for clear and consistent provisions \nrequiring the evaluation of least-cost options like alternative transmission technologies to \nmitigate the rate impact on all transmission customers.    \n68. \nNYISO should explain whether the Tariff remains just and reasonable without \nprovisions that (1) require the evaluation of alternative transmission technologies in \n \n172 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). \n173 Improvements to Generator Interconnection Procs. & Agreements, Order  \nNo. 2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), \norder on reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC  \n¶ 61,134 (2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & \nCost Allocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order \nNo. 1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC  \n¶ 61,026 (2025)."},{"page":45,"startToken":17340,"endToken":17834,"text":"Docket No. EL26-69-000 \n- 45 - \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. \n69. \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.174  To the extent NYISO or the Transmission Owners already have such \nprocedures and conduct such studies, but those processes are not included in the Tariff, \nNYISO and the Transmission Owners should explain their existing processes and \nconsider whether amendments are necessary to the Tariff to memorialize those processes \nand also address the concerns expressed herein.  Otherwise, NYISO should explain \nwhether the Tariff remains just and reasonable without:  (1) sufficiently clear and \nconsistent provisions to evaluate the impact of providing the requested transmission \nservice to Eligible Customers on behalf of large loads, including identifying the Direct \nAssignment Facilities and Network Upgrades necessary to provide such service reliably; \n(2) provisions to appropriately recognize within the transmission service study process \n \n174 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."},{"page":46,"startToken":17834,"endToken":18292,"text":"Docket No. EL26-69-000 \n- 46 - \nthe unique operational characteristics of large loads; (3) a study deadline of no more than \n60-90 calendar days; or propose Tariff revisions establishing them. \n70. \nThird, we preliminarily find that NYISO’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.175  For example, we are concerned that NYISO’s Tariff does not require \ntransmission customers to provide NYISO hourly forecasts, telemetry data, and other \ndata to ensure sufficient visibility or specify requirements for maintaining communication \nchannels between NYISO 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 NYISO 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 NYISO 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 NYISO 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.176  NYISO should explain whether the \nTariff remains just and reasonable without these or other ongoing operational \n \n175 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. \n176 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 109, \n113."},{"page":47,"startToken":18292,"endToken":18741,"text":"Docket No. EL26-69-000 \n- 47 - \nrequirements as part of the rates, terms, and conditions of transmission service or propose \nTariff revisions establishing necessary ongoing operational requirements. \n71. \nFourth, we preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable because it lacks pro forma provisions in a transmission service agreement \nbetween NYISO and the transmission customer taking transmission service on behalf of a \nlarge load to memorialize the above terms (e.g., equipment requirements, data \nrequirements, remote disconnect capability).  We are concerned that, without such pro \nforma provisions in a transmission service agreement between NYISO and the \ntransmission customer, NYISO may be unable to enforce ongoing operational \nrequirements for transmission customers taking transmission service on behalf of large \nloads.  NYISO 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 NYISO and the transmission customer. \nB. \nCost Shifting Risk Among Transmission Customers \n72. \nWe next preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable because it lacks adequate mechanisms to mitigate the risk of cost  \nshifting among transmission customers, which may result in unjust and unreasonable \nrates for transmission service.  In particular, we are concerned about the apparent lack \nof (1) transparency regarding the assignment of Network Upgrades, and their associated \ncosts, that are needed to provide transmission service to Eligible Customers on behalf of \nlarge loads; and (2) a pro forma cost recovery agreement between NYISO, 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. \n73. \nWe direct NYISO and the Transmission Owners, to the extent the matters \naddressed herein implicate aspects of the Tariff over which they have the filing rights, to \nexplain whether the Tariff remains just and reasonable without:  (1) robust, accurate, and \nsystematic provision of data on NYISO’s website in a single location, and in an easily \naccessible format that is searchable and allows users to filter the data, regarding the cost \nfor Network Upgrades needed to provide transmission service to Eligible Customers on \nbehalf of large loads; and (2) a pro forma cost recovery agreement between NYISO, the \nrelevant transmission owner, and the Eligible Customer taking transmission service on \nbehalf of a large load, or to propose Tariff revisions to provide additional transparency \nand establish such a pro forma cost recovery agreement.  We encourage state regulators \nresponsible for setting retail rates to provide input to NYISO regarding their transparency \nneeds."},{"page":48,"startToken":18741,"endToken":19202,"text":"Docket No. EL26-69-000 \n- 48 - \n1. \nJurisdiction \n74. \nThe Commission has a duty to address the risk of cost shifting among transmission \ncustomers that may result in unjust and unreasonable transmission rates.  As explained \nabove, the Commission is obligated to ensure that the rates charged for jurisdictional \ntransmission service—as well as any practice directly affecting such rates—are just and \nreasonable and not unduly discriminatory or preferential.  With respect to the addition of \nlarge loads to the transmission system, the Commission has exclusive authority to ensure \nthat transmission rates are just and reasonable.  The costs of those upgrades to the \ntransmission system (i.e., Network Upgrades) necessary to provide transmission service \nto Eligible Customers on behalf of large loads are inputs to jurisdictional transmission \nrates, and thus directly affect the Commission-jurisdictional rates paid by transmission \ncustomers.  To fulfill its responsibility to ensure that transmission rates are just and \nreasonable, the Commission must act to address the risk of cost shifting among \ntransmission customers due to (1) the process transmission providers and/or transmission \nowners use to evaluate the facilities needed, and the associated costs, for the provision of \ntransmission service to Eligible Customers on behalf of large loads and (2) speculative \ntransmission service requests by Eligible Customers on behalf of large loads that could \nresult in unjust and unreasonable transmission rates. \n75. \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.177  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.178  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.179  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,180 as well as voluntary efforts by transmission owners to protect \n \n177 See, e.g., National Grid November 21 ANOPR Comments at 4, 13-16; New \nYork Commission November 21 ANOPR Comments at 7-8; NY UIU November 21 \nANOPR Comments at 2, 9-11; NYTOs November 21 ANOPR Comments at 14-15. \n178 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. \n179 Id. P 68. \n180 See, e.g., National Grid November 21 ANOPR Comments at 4; NYTOs \nNovember 21 ANOPR Comments at 16; see also EEI March 12 ANOPR Comments,"},{"page":49,"startToken":19202,"endToken":19643,"text":"Docket No. EL26-69-000 \n- 49 - \nretail ratepayers through cost recovery agreements with large loads.181  We are also \nencouraged by the execution of the President’s Ratepayer Protection Pledge, through \nwhich data center developers have committed to shield retail ratepayers from increased \nelectricity prices.182   \n76. \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 \n77. \nWe preliminarily find that NYISO’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 NYISO’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 \nevaluated in the local transmission planning process that are needed to provide \ntransmission service to Eligible Customers on behalf of those large loads, and the costs \n \nattach. 1 at 9-13; NARUC April 13 ANOPR Comments; New York Commission \nNovember 21 ANOPR comments at 7 (stating that it could reform New York retail \nelectricity tariffs to ensure that large loads do not “impose unjust and unreasonable costs \nupon other retail consumers”). \n181 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). \n182 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":50,"startToken":19643,"endToken":20061,"text":"Docket No. EL26-69-000 \n- 50 - \nfor those Network Upgrades.  We preliminarily find that cost transparency measures are \nneeded to provide stakeholders with sufficient information and visibility regarding the \nNetwork Upgrades, and their associated costs, needed to provide transmission service to \nEligible Customers on behalf of large loads.    \n78. \nWe recognize that NYISO requires transmission owners to provide NYISO \nquarterly updates for load interconnections that have completed a Load SIS; however, \nthese SIS reports do not include information on the scope or costs of Network Upgrades, \nnor does NYISO appear to publicly post individual reports or an aggregate of the \ninformation it obtains.183   \n79. \nHowever, NYISO’s Tariff does not appear to require that information identifying \nthe Network Upgrades needed to provide transmission service to Eligible Customers on \nbehalf of large loads and the costs of those Network Upgrades determined through these \nlocal transmission planning processes be readily available on NYISO’s website in a \nsingle location, and in an easily accessible format that is searchable and allows users to \nfilter the data.  The speed and scale with which Eligible Customers are seeking \ntransmission service on behalf of large loads makes it difficult for interested parties, \nincluding transmission customers and state regulators, to accurately assess which \ntransmission costs are driven by requests for transmission service by Eligible Customers \nto serve large loads.  As NYISO itself indicates, load interconnection requests in its \ninterconnection queue have grown from six projects totaling 1,045 MW in 2022 to more \nthan 40 projects totaling more than 10,000 MW as of November 2025.184  We are \nconcerned that the potentially speculative nature of requests for transmission service by \nEligible Customers on behalf of large loads,185 the speed and scale with which large loads \nare seeking to be added to the transmission system, the projected need for significant \nNetwork Upgrades to provide transmission service to Eligible Customers on behalf of \nlarge loads,186 and the lack of centralized information on the associated transmission \ncosts in NYISO hamper the ability of the Commission and stakeholders (including \n \n183 NYISO, Manual 6 ‘Load Forecasting Manual’, Appendix A ‘Load Forecast \nReporting for Large Load Facility Interconnections’ (Oct. 2025), \nhttps://www.nyiso.com/documents/20142/2924447/load_fcst_mnl.pdf/a694b1c4-7d1b-\n9382-d171-ff2fbd7ccd0c. \n184 NYISO November 21 ANOPR Comments at 2. \n185 See supra P 62.  \n186 See National Grid November 21 ANOPR Comments at 16-17 (noting that the \n“unprecedented additions of large loads to the transmission system” underscores the need \nto apply the “beneficiary pays” approach to Network Upgrades costs)."},{"page":51,"startToken":20061,"endToken":20528,"text":"Docket No. EL26-69-000 \n- 51 - \ntransmission customers and state regulators187) to understand and accurately assess the \nrelationship between the addition of large loads to the transmission system and wholesale \ntransmission costs.   \n80. \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 process188 that are \nneeded to provide transmission service to Eligible Customers on behalf of large loads.  \nNYISO must provide clear, timely, and detailed information regarding the extent to \nwhich requests 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 \n187 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 RTOS/ISO do not have to clearly explain when a “‘bucket of costs is specifically for \nthis large load” and noting that “if we, at the state level, can’t see the driver [of \ntransmission costs], we can’t assign the cost to the causer[,] [a]nd so we need that \nclarity”), 69-70 (Chair Myers, Arizona) (“[B]eing able to allocate the large load costs to \nthe correct bucket when it gets to the states is kind of a top priority.”).   \n188 Our concern with transparency regarding Network Upgrades needed to provide \ntransmission service to Eligible Customers on behalf of large loads, as well as the costs of \nsuch upgrades, is limited to Network Upgrades planned through the local transmission \nplanning process.  While we acknowledge that in Order No. 890, the Commission \nadopted requirements for RTOs/ISOs, as well as for transmission owners to the extent \nthat they perform transmission planning within an RTO/ISO, to have open and \ntransparent transmission planning processes, there are additional requirements that apply \nto regional transmission planning processes (that do not apply to local transmission \nfacilities) and thus is relevant to the distinction here.  Specifically, under Order No. 1000, \npublic utility transmission providers, including RTOs/ISOs, must evaluate as part of their \nregional transmission planning process whether there are transmission facilities that more \nefficiently or cost-effectively meet the transmission planning region’s identified \ntransmission needs.  See Order No. 1000, 136 FERC ¶ 61,051 at P 11."},{"page":52,"startToken":20528,"endToken":21011,"text":"Docket No. EL26-69-000 \n- 52 - \n81. \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.189        \n82. \nAccordingly, we preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable because it does not require the provision of data on NYISO’s website in a \nsingle location, and in an easily accessible format that is searchable and allows users to \nfilter the data, that identifies the Network Upgrades that are needed to accommodate \nrequests for transmission service by Eligible Customers on behalf of large loads, and the \ncosts of those Network Upgrades.  NYISO should explain whether the Tariff remains just \nand reasonable without provisions that would require NYISO and the Transmission \nOwners to publicly post and regularly update data that details:  (1) the aggregate amounts \nof proposed large load additions in NYISO’s footprint, including the aggregate amounts \nin each transmission pricing zone; (2) the planned Network Upgrades needed to provide \ntransmission service to Eligible Customers on behalf of large loads, identified by type of \nequipment and Network Upgrade (e.g., new substation, reconductoring, a new high-\nvoltage transmission line) for each transmission service request; and (3) cost estimates for \nthose Network Upgrades, or propose such Tariff revisions.  NYISO and the Transmission \nOwners should also consider what other data related to transmission costs resulting from \nthe provision of transmission service to Eligible Customers on behalf of large loads \nwould be useful to include on NYISO’s website.  To the extent there are concerns about \ndata confidentiality, NYISO and the Transmission Owners should consider whether there \nare ways to mitigate those concerns while still providing the necessary transparency. \n \n189 See NY UIU November 21 ANOPR Comments at 11-12 (noting a general need \nfor cost transparency with respect to large loads); see also OCC November 21 ANOPR \nComments at 3 (“Consumers, state advocates and state regulatory commissions have a \nright to know which entities are seeking large-load interconnections, the nature of the \nrequested service, and how related costs could flow through to transmission and \ndistribution rates.”); U.S. House of Representatives Committee on Energy and Commerce \nRanking Members November 21 ANOPR Comments at 2 (urging the Commission to \n“require sufficient transparency from grid operators so it can determine which specific \nlarge load facilities are responsible for grid upgrade needs”); CPUC November 21 \nANOPR Comments at 16-17 (asserting that the public posting of large load cost \nresponsibility determinations would improve transparency, to the benefit of businesses \nand ratepayers)."},{"page":53,"startToken":21011,"endToken":21444,"text":"Docket No. EL26-69-000 \n- 53 - \n3. \nCost Recovery Agreements \n83. \nWe next preliminarily find that NYISO’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 NYISO, the relevant transmission owner, and the \nEligible Customer taking transmission service on behalf of large loads that help ensure \nthat Eligible Customers bear the risk and are ultimately responsible for costs incurred to \nprovide transmission service, including the cost of Network Upgrades.  \n84. \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.190  Commenters also argue that retail-level large load tariffs do not \nprotect wholesale transmission customers from cost shifting.191  Specifically, commenters \nin the record contend that, while a retail-level large load tariff protects the load serving \nentity taking wholesale transmission service and its retail customers, it fails “to provide \nany mechanism to protect other wholesale transmission customers” from stranded \ntransmission costs.192  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 \n \n190 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. \n191 TAPS November 21 ANOPR Comments at 26 (“[A] number of state \ncommissions are moving forward with retail large load tariffs, which provide for varying \nprotections, but may not require the revenues and minimum demand levels to be included \nin wholesale transmission rates.”); Buckeye November 21 ANOPR Comments at 14-16; \nKansas Commission November 21 ANOPR Comments at 15-16. \n192 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 \nANOPR Comments at 26-27 & nn.50-51."},{"page":54,"startToken":21444,"endToken":21889,"text":"Docket No. EL26-69-000 \n- 54 - \ntransmission grid.”193  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.194   \n85. \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 \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.   \n86. \nNYISO’s Tariff does not require cost recovery agreements between NYISO, 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.   \n87. \nAccordingly, we preliminarily find that, in order to prevent unjust and \nunreasonable cost shifting among transmission customers, it appears necessary for \nNYISO, 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 \n \n193 Kansas Commission November 21 ANOPR Comments at 11-12.  \n194 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)."},{"page":55,"startToken":21889,"endToken":22334,"text":"Docket No. EL26-69-000 \n- 55 - \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.195  Our preliminary finding is not intended to alter or call into question \nexisting regional cost allocation methods for Network Upgrades, but instead is focused \non helping to prevent cost shifting among transmission customers.   \n88. \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 \nrequirement.196  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.197  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 \n \n195 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). \n196 See supra note 181. \n197 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":56,"startToken":22334,"endToken":22816,"text":"Docket No. EL26-69-000 \n- 56 - \ntransmission customers than an agreement between the transmission owner and the \nEligible Customer would.   \n89. \nIn addition to our preliminary finding that NYISO’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 \nNYISO and/or Transmission Owners will study the requested transmission service and \ndetermine any necessary Network Upgrades that must be developed to provide the \nrequested 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 \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.  NYISO 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.198  \n90. \nAlthough the Commission’s concerns surrounding cost shifting described above \nmay not present the same in NYISO as in other RTOs/ISOs, we remain concerned that \ncost shifting may occur.  We acknowledge that NYISO has a wholesale load \ninterconnection process and that Eligible Customers may request that optional studies be \nconducted during the transmission service request process.  We note that portions of the \nwholesale load interconnection process are not in NYISO’s Tariff, including the \ntransmission owners’ Facilities Study for Network Upgrades, as well as the \ninterconnection agreement between the transmission owner and the Eligible Customer, \nwhich memorializes the final costs of and cost allocation for the Network Upgrades \nidentified in the load interconnection process.  We also note that the optional studies \n \n198 See infra P 133."},{"page":57,"startToken":22816,"endToken":23213,"text":"Docket No. EL26-69-000 \n- 57 - \nconducted at the request of Eligible Customers during the transmission service request \nprocess may result in Network Upgrades or Transmission Projects for which the terms of \nconstruction and cost allocation are memorialized in an interconnection agreement (e.g., a \nTransmission Project Interconnection Agreement).  We remain concerned that cost \nshifting may occur through the recovery of the transmission revenue requirement in the \nTransmission Service Charge, including for transmission projects planned through the \nLocal Transmission Planning Process to accommodate speculative requests for \ntransmission service by Eligible Customers on behalf of large loads, i.e., where large \nloads do not materialize or where the MW quantity of such large loads is lower than \nproposed, or because of the study process used to evaluate the facilities needed, and the \nassociated costs, to accommodate the provision of transmission service to Eligible \nCustomers on behalf of large loads.    \n91. \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.199  We preliminarily find that it appears \nreasonable for filers of formula rates to provide a separate workpaper in the annual \ninformational filing describing how any payments made pursuant to a cost recovery \nagreement are reflected in the transmission owner’s transmission formula rate. \nC. \nCo-Location Arrangements and Load with Behind the Meter \nGeneration \n92. \nThe Commission recently addressed in the PJM region the need for sufficiently \nclear and consistent tariff provisions addressing the rates, terms, and conditions that  \napply to co-location arrangements and for transmission services that reflect an Eligible \nCustomer taking transmission service on behalf of Eligible Load200 that is willing and \nable to limit its energy withdrawals from the transmission system under certain \nconditions.201  As discussed below, NYISO’s Tariff appears to be unjust and \nunreasonable because it lacks such provisions.  \n \n199 See 18 C.F.R. pt. 101 (2025). \n200 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 98. \n201 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 2; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at PP 91, 102."},{"page":58,"startToken":23213,"endToken":23620,"text":"Docket No. EL26-69-000 \n- 58 - \n93. \nWe direct NYISO and the Transmission Owners, to the extent the matters \naddressed herein implicate aspects of the Tariff over which they have the filing rights, to \nexplain whether the Tariff remains just and reasonable without provisions addressing the \nrates, terms and conditions that apply to interconnection customers serving co-located \nload and for Eligible Customers taking transmission service on behalf of Eligible Load, \nor propose Tariff revisions establishing the rates, terms, and conditions that apply to co-\nlocation arrangements.  We recognize that NYISO is currently considering reforms \nrelated to co-location arrangements in its stakeholder process and we again encourage \nNYISO to consider whether these efforts would, either fully or in part, address the \nCommission’s concerns that the Tariff appears to be unjust and unreasonable.   \n1. \nDefinition \n94. \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.”202  The PJM Co-\nLocation Order used the term co-location arrangement when referring to both the co-\nlocated load and the associated generator.203   \n95. \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 \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. \n96. \nNYISO defines Behind-the-Meter Net Generation Resource (BTM:NG Resource), \nin relevant part, as:  \nA facility within a defined electrical boundary comprised of a \nGenerator and a Host Load located at a single point identifier \n(PTID), where the Generator routinely serves, and is assigned \nto, the Host Load and has excess generation capability after \nserving that Host Load.  The Generator of the BTM:NG \nResource must be electrically located in the NYCA, have a \nminimum nameplate rating of 2 MW and a minimum net \ninjection to the NYS Transmission System or distribution \nsystem of 1 MW.  The Host Load of the BTM:NG Resource \n \n202 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164 (alterations in original). \n203 Id. P 3."},{"page":59,"startToken":23620,"endToken":23973,"text":"Docket No. EL26-69-000 \n- 59 - \nmust also have a minimum [Average Coincident Host Load] \nof 1 MW.  A facility that otherwise meets these eligibility \nrequirements, but either (i) is an Intermittent Power Resource \nor Energy Storage Resource, (ii) whose Host Load consists \nonly of Station Power, or (iii) has made an election pursuant \nto Section 5.12.1.12, does not qualify to be a BTM:NG \nResource.204 \n97. \nNYISO defines Host Load as:  \nThe Load that is electrically interconnected within the defined \nelectrical boundary of a BTM:NG Resource that is routinely \nserved by, and assigned to, the Generator of a BTM:NG \nResource.  Station Power will be included in the calculation \nof the BTM:NG Resource’s Host Load if it is self-supplied by \nthe Generator of the BTM:NG Resource, and it is not \nseparately metered pursuant to Section 5.12.6.1.1 and ISO \nProcedures.205 \n98. \nFor purposes of this order, we will use the term Eligible Load to refer to co-\nlocated load and/or load with a BTM:NG Resource.206 \n2. \nJurisdiction \n99. \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.207  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 \n \n204 NYISO MST, § 2.2 (Definitions – B) (18.0.0).  While we believe this definition \nis sufficient for purposes of this order, responses may explain whether changes to the \ndefinition of BTM:NG may be needed in order to comply with any future directives, \nshould the Commission find that the Tariff has in fact become unjust and unreasonable. \n205 Id. § 2.8 (Definitions – H) (3.0.0). \n206 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91. \n207 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)."},{"page":60,"startToken":23973,"endToken":24363,"text":"Docket No. EL26-69-000 \n- 60 - \ngenerator interconnects to dual-use distribution facilities.208  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.209  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.210   \n100. Additionally, 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.211 \n3. \nTariff Provisions \n101. We preliminarily find that NYISO’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 NYISO’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.   \n102. The 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 NYISO’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 \n \n208 Id. P 172 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, \n1282 (D.C. Cir. 2007)). \n209 Id. P 173. \n210 Id. P 174. \n211 Id. PP 167-169."},{"page":61,"startToken":24363,"endToken":24820,"text":"Docket No. EL26-69-000 \n- 61 - \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,212 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.   \n103. Moreover, 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 \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,”213 and that costs must be allocated in a manner that is at least roughly \ncommensurate with the benefits that entity receives.214 \n104. We preliminarily find that NYISO’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 NYISO performs as part of its existing study process to evaluate the \nimpacts 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.215  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 \n \n212 Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th 1307, 1312 (D.C. Cir. \n2023). \n213 Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368. \n214 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d at 476. \n215 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":62,"startToken":24820,"endToken":25274,"text":"Docket No. EL26-69-000 \n- 62 - \ndetails a process—including the existing rules and studies applicable to such generator \ninterconnection arrangements—are not sufficiently detailed in the Tariff to ensure clarity \nfor how interconnection customers may seek to serve co-located load.  Moreover, without \nan Eligible Customer designated to take transmission service on behalf of a co-located \nload, there is no mechanism for NYISO to address situations in which a co-located load \nwithdraws energy from the transmission system.   \n105. Therefore, we preliminarily find that NYISO’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.  NYISO should explain whether the Tariff remains \njust and reasonable without such provisions or propose Tariff revisions.  \n106. We have similar concerns regarding NYISO’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.216  \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 \nloads must pay for these ancillary services on a gross demand basis.217  In the PJM Co-\nLocation Rehearing Order, the Commission applied these findings to Eligible Customers \ntaking transmission service on behalf of load with behind the meter generation.218  \nHowever, NYISO’s Tariff does not appear to include a mechanism by which an Eligible \nCustomer, on behalf of Eligible Load, would be charged for ancillary services \ncommensurate with its usage of such services, particularly if such customer did not \nwithdraw energy from the transmission system.   \n107. Therefore, we preliminarily find that NYISO’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 \n \n216 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 183. \n217 Id. PP 184-185. \n218 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 400."},{"page":63,"startToken":25274,"endToken":25745,"text":"Docket No. EL26-69-000 \n- 63 - \nresidential customers, among others.219  NYISO 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. \n108. The 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.220  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 behind the meter generation.221  We are concerned that \nNYISO’s Tariff lacks transmission services that would reflect the ability of Eligible \nCustomers on behalf of Eligible Load to take transmission services that align with their \nuse of the transmission system, which may result in inefficient and costly transmission \nbuildout and costs paid by transmission customers.222    \n109. Therefore, we also preliminarily find that NYISO’s Tariff appears to be unjust and \nunreasonable 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.  NYISO \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, \nNYISO 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 \n \n219 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 159. \n220 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199. \n221 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 101-103. \n222 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":64,"startToken":25745,"endToken":26178,"text":"Docket No. EL26-69-000 \n- 64 - \ntransmission services (transmission service up to a specified MW quantity, i.e., the \ncontract level, on a firm or non-firm basis).  Finally, we note that the Commission has \nfound it just and reasonable that, in order for an Eligible Customer to take interim NITS, \nfirm contract demand transmission service, and non-firm contract demand transmission \nservice, an Eligible Customer must have necessary control technologies and/or protection \nsystems, which may include a special protection scheme, to limit its energy withdrawals \nto its approved level.223 \n110. Finally, we preliminarily find that NYISO’s Tariff is unjust and unreasonable \nbecause it allows load with behind the meter generation to net its behind the meter \ngeneration against its load for purposes of calculating Transmission Service Charges for \nHost Loads configured in a BTM:NG Resource arrangement.  In the PJM Co-Location \nOrder, the Commission found that PJM’s behind the meter generation rules, which \nallowed load serving entities that provide service to loads with qualifying behind the \nmeter generation to reduce their costs by netting output from behind the meter generation \nin the calculation of their peak demand for the purpose of determining NITS charges, \nwere unjust and unreasonable.224  The Commission concluded that PJM’s behind the \nmeter generation rules were no longer consistent with cost causation principles because \nlarge loads configured in a behind the meter generation arrangement with significant \ngeneration will raise cost shifting concerns compared to loads pursuing smaller amounts \nof netting.225  The Commission also found that such rules could lead to reliability and \nresource adequacy risks because PJM is obligated to serve transmission customers using \nbehind the meter generation, but does not consider such customers in transmission and \nresource adequacy planning.226  The Commission directed PJM to revise its retail behind \nthe meter generation rules, including establishing a MW threshold for the amount of load \nat a particular electrical location that network customers may net by using behind the \nmeter generation .227  We are similarly concerned that NYISO’s Tariff allows Eligible \nCustomers that take transmission service on behalf of Host Loads configured in a \nBTM:NG Resource arrangement to be charged based on actual energy withdrawals rather \nthan gross load for the applicable Transmission Service Charge.228  NYISO should \nexplain whether the Tariff remains just and reasonable even though it allows netting of \n \n223 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480 \n224 PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 7, 186. \n225 Id. P 186. \n226 Id.  \n227 Id. P 221. \n228 NYISO Tariff, § 2.7.2.; id. § 6.9 (Schedule 9) (2.0)."},{"page":65,"startToken":26178,"endToken":26619,"text":"Docket No. EL26-69-000 \n- 65 - \nbehind the meter generation from gross load for purposes of determining applicable \nTransmission Service Charges for Host Loads configured in a BTM:NG Resource \narrangement or propose Tariff revisions.  Recognizing potential impacts on existing \ncustomers, we note that NYISO may explain whether current BTM:NG rules for \ncustomers that fall below a new MW materiality threshold for the amount of load at a \nparticular electrical location that transmission customers may net using BTM:NG \nResources remain just and reasonable. \nD. \nExtending New Transmission Services to Eligible Customers Taking \nService on Behalf of Flexible Large Loads \n111. 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 loads229 can quickly and verifiably adjust \ntheir consumption in response to system conditions or price signals.230  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.231  In recognition of this \nflexibility, many commenters support new transmission services that reflect the \noperational capabilities of flexible large loads, including interim NITS while Network \nUpgrades are constructed and non-firm transmission service.232 \n \n229 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. \n230 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. \n231 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. \n232 See, e.g., Constellation November 21 ANOPR Comments at 24-25; Calibrant \nNovember 21 ANOPR Comments at 2-4; Critical Loop November 21 ANOPR"},{"page":66,"startToken":26619,"endToken":27005,"text":"Docket No. EL26-69-000 \n- 66 - \n112. We preliminarily find that NYISO’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 NYISO are \nNITS and firm Point-to-Point Transmission Service.233  While these remain just and \nreasonable options for an Eligible Customer to take on behalf of a flexible large load, \nbased on the record before us, we preliminarily find that new transmission services \nshould be available to reflect the operational reality that large loads may use the \ntransmission system to differing extents and certain large loads are willing and able to \nlimit their use of the transmission system under certain conditions.234  As explained \nabove, the Commission found that Eligible Customers taking transmission service on \nbehalf of Eligible Load 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.235  As the record suggests, Eligible Customers taking transmission \nservice on behalf of flexible large load also may be willing and able to limit their use of \nthe transmission system under certain conditions.  As recognized in the ANOPR record, \nload flexibility can avoid inefficient and costly transmission system build-out.236  In \naddition, transmission services that reflect that flexible large loads are willing and able to \nlimit their withdrawals from the transmission system under certain conditions could help \n \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. \n233 See supra P 20 (describing existing transmission services in NYISO). \n234 See supra P 111. \n235 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at P 103. \n236 See supra P 111; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at PP \n160, 177, 199 (finding that new transmission service options reflect a co-located load’s \nability to limit withdrawals from the transmission system and potentially avoid costly and \ninefficient transmission system buildout that may not be necessary)."},{"page":67,"startToken":27005,"endToken":27419,"text":"Docket No. EL26-69-000 \n- 67 - \ntimely interconnect flexible large loads.237  Entities in the NYISO footprint acknowledge \nthe importance of facilitating load flexibility.238 \n113. Therefore, we are concerned that NYISO’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.  NYISO 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, NYISO \nshould explain whether the Tariff remains just and reasonable without (1) an interim non-\nfirm network transmission service while Network Upgrades are being constructed (i.e., \ninterim 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.239 \nE. \nInterconnection Customers Serving Electrically Proximate Large Load \nand Co-Located Load \n114. In response to the ANOPR, a number of commenters agree that the ability to  \nstudy new load and new generation together, when physically or electrically proximate, \npresents system benefits and can help address the challenges posed by large load \n \n \n237 See supra P 111; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at PP \n201 (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). \n238 National Grid November 21 ANOPR Comments at 19-20; NYISO November \n21 ANOPR Comments at 8-9; NY UIU November 21 ANOPR Comments at 6-8.  \n239 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480."},{"page":68,"startToken":27419,"endToken":27772,"text":"Docket No. EL26-69-000 \n- 68 - \nadditions.240  Commenters argue that studies that consider large load and generation \ntogether present a more complete picture of the grid and can enable the identification of \nmore accurate, efficient, and cost-effective transmission solutions by minimizing system \nimpacts.241  As a result, this can speed up the interconnection process for both large loads \nand generation, and shorten energization timelines,242 which commenters contend \nreduces uncertainty for both parties243 and “is necessary to match the pace of AI \ninnovation in the United States.”244  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.245  Other benefits to a joint study identified by commenters include \nimproving load forecasting and siting decisions246 and reducing the need for critical \nsupply chain components.247   \n \n240 See e.g., DCC November 21 ANOPR Comments at 5-6; DTE November 21 \nANOPR Comments at 11; Google November 21 ANOPR Comments at 7; International \nEnergy Credit Association November 21 ANOPR Comments at 10; Terraflux November \n21 ANOPR Comments at 1. \n241 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. \n242 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. \n243 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 \nANOPR Comments at 8. \n244 Microsoft November 21 ANOPR Comments at 8-9. \n245 CEBA November 21 ANOPR Comments at 8. \n246 ELCON November 21 ANOPR Comments at 5; Maryland Commission \nNovember 21 ANOPR Comments at 6-7.  \n247 AEU November 21 ANOPR Comments at 13."},{"page":69,"startToken":27772,"endToken":28163,"text":"Docket No. EL26-69-000 \n- 69 - \n115. 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 \nstudies and inefficient system build-out.248  For example, Eolian states that in its \nexperience developing a project in PJM, the failure of the generator interconnection study \nprocess to reflect reasonably expected load conditions on the grid models triggered overly \ncostly Network Upgrades and caused the cancellation of generation project that could \nhave reliably served adjacent load growth.249   \n116. 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.250  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.251  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.252  Commenters contend that if large load interconnection proceeds more \nquickly than new generation can come online, the result could be price increases for \nconsumers.253   \n117. A number of commenters support expedited interconnection studies for new \ngeneration paired with load.254  Some commenters argue that one solution to generator \n \n248 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. \n249 Eolian May 19 ANOPR Comments at 10. \n250 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.  \n251 Oracle November 21 ANOPR Comments at 1. \n252 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)). \n253 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR \nComments at 6-7, 11.  \n254 See, e.g., DTE November 21 ANOPR Comments at 8; ENGIE November 21 \nANOPR Comments at 4; International Energy Credit Association November 21 ANOPR"},{"page":70,"startToken":28163,"endToken":28541,"text":"Docket No. EL26-69-000 \n- 70 - \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.255  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.256  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.257   \n1. \nJurisdiction \n118. 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.258  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.259  In the PJM Co-Location Order, the Commission observed that a generator’s \n \nComments at 8; Meta November 21 ANOPR Comments at 5-6; Ohio FEA November 21 \nANOPR Comments at 5.  \n255 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.  \n256 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. \n257 Constellation June 5 ANOPR Comments at 8-9. \n258 16 U.S.C. § 824(b)(1). \n259 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":71,"startToken":28541,"endToken":28940,"text":"Docket No. EL26-69-000 \n- 71 - \ninterconnection to the interstate transmission system “does not fall outside of the \nCommission’s jurisdiction merely because there is [c]o-[l]ocated [l]oad behind the \ngenerator’s point of interconnection.”260  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.   \n119. We recognize that states have exclusive authority over resource planning and the \ngeneration mix within their boundaries.261  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,262 and has approved interconnection processes that allow \ncertain generating facilities to interconnect more quickly by replacing a retiring existing \ngenerating facility.263   \n2. \nDefinitions \n120. 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,264 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, \n \n260 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. \n261 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 (citing \n16 U.S.C. § 824(b)(1)).  \n262 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, \n163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order  \nNo. 845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B,  \n168 FERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; PJM \nInterconnection, L.L.C., 190 FERC ¶ 61,083 (2025). \n263 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); \nMidcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019).  \n264 See supra P 64."},{"page":72,"startToken":28940,"endToken":29392,"text":"Docket No. EL26-69-000 \n- 72 - \nwill be effectively the same as if they were located at the same substation (e.g., large load \nthat is located no more than two substations away from the generating facility).  We will \nconsider proposed revisions to this definition that ensure it is appropriately tailored to \nNYISO transmission system \n3. \nTariff Provisions \n121. We preliminarily find that NYISO’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,265 that has a high peak load (i.e., large co-located loads that are 50 MW or \ngreater).266  Specifically, we preliminarily find that NYISO’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 NYISO’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,267 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,268 thereby potentially \n \n265 See supra P 95. \n266 We note that generator interconnection service in and of itself does not convey \ntransmission service. \n267 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n268 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":73,"startToken":29392,"endToken":29828,"text":"Docket No. EL26-69-000 \n- 73 - \nreducing the need for Network Upgrades, which can accelerate the generator \ninterconnection process.269  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.270   \n122. 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.271  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, \n \n \n269 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.”).  \n270 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. \n271 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."},{"page":74,"startToken":29828,"endToken":30267,"text":"Docket No. EL26-69-000 \n- 74 - \nincreasing Network Upgrade costs.272  The same result may occur in the absence of new \ngenerator interconnection study procedures and generator interconnection services \ntailored to a new generating facility coming online for the express purpose of serving an \nelectrically proximate large load or large co-located load.273   \n123. 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.274  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.”275  We do not expect or propose that NYISO 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 NYISO’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.276  To the extent that the interconnection customer’s \n \n272 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible \nCustomers taking service on behalf of Co-Located Loads that do not reserve \ntransmission . . . requiring such Eligible Customers to take NITS on behalf of these Co-\nLocated Loads may in some circumstances result in costly and inefficient transmission \nsystem buildout that may not be necessary if such Eligible Customers are willing and able \nto take a transmission service that requires fewer Network Upgrades to provide, and \ntherefore may result in lower Network Upgrade costs, than would NITS.”). \n273 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).  \n274 SPP HILL Order, 194 FERC ¶ 61,031. \n275 Id. P 64. \n276 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 NYISO’s transmission system"},{"page":75,"startToken":30267,"endToken":30704,"text":"Docket No. EL26-69-000 \n- 75 - \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.   \n124. Another potentially reasonable approach to address our concerns could be to \ndevelop a generator interconnection study process that would allow the use of existing \nERIS or NRIS of an existing generator to connect a new generating facility and a new \nlarge load behind the same point of interconnection of the existing generator with \nnecessary control technologies and/or protection systems, which may include a special \nprotection scheme, that ensure that the net injection does not exceed the amount in the \nexisting generator interconnection agreement.277  Such an approach could expedite the \ninterconnection study process for a generator planning to serve an electrically proximate \n(in this case at the same point of interconnection) large load.278  An additional potentially \nreasonable approach could be a new load-limited generator interconnection service that \nallows a new generating facility and new large co-located load seeking to interconnect \nbehind the same new point of interconnection, with necessary control technologies and/or \nprotection systems, which may include a special protection scheme, to ensure that there is \nno injection to the transmission system.279  It may be reasonable for such a load-limited \ngenerator interconnection service to be or not to be of an interim nature.  We invite \nNYISO and/or Transmission Owners, in responding to this order or in an FPA section \n \nmay warrant consideration of a more limited definition of electrically proximate.  See \nDuke November 21 ANOPR Comments at 21-22; DTE November 21 ANOPR \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. \n277 See Constellation June 5 ANOPR Comments at 1-2, 10-13. \n278 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”). \n279 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 \nANOPR Comments at 13-14."},{"page":76,"startToken":30704,"endToken":31167,"text":"Docket No. EL26-69-000 \n- 76 - \n205 filing, to submit original proposals designed to address the concerns expressed herein \nand tailored to their unique circumstances.  \n125. 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 NYISO’s current \ngenerator interconnection process failing to keep pace with the new large loads seeking to \nbe integrated onto NYISO’s transmission system.280  We preliminarily find that this \noutcome may be unjust and unreasonable because reliance on NYISO’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. \n126. NYISO 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 co-\nlocated 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. \n127. Given that generator interconnection service in and of itself does not convey \ntransmission service, we encourage NYISO to consider, in responding to these concerns, \n \n280 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":77,"startToken":31167,"endToken":31605,"text":"Docket No. EL26-69-000 \n- 77 - \nwhat type of transmission service an Eligible Customer will need to take on behalf of the \nelectrically proximate large load or large co-located load.281  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.282 \nF. \nInformational Report \n128. 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.283  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.284  We are concerned that NYISO and load serving entities \nare unable to plan adequate generation to serve all load at the pace such load seeks to \nconnect.   \n129. Accordingly, we direct NYISO to submit in Docket No. EL26-69-000, within 30 \ndays of the date of issuance of this order, a detailed informational report on any proposals \nunder consideration in its stakeholder process to address the issue of resource adequacy \nto serve new large loads.  We also strongly encourage new proposals to the extent \nnecessary to address these concerns.  The informational report must include a detailed \nschedule of key milestones, such as stakeholder or NYISO Board votes, that includes the \nestimated date on which NYISO expects to file any such proposals with the Commission.  \n \n281 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. \n282 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. \n283 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; NY UIU November 21 ANOPR Comments at 10-11; NYISO \nNovember 21 ANOPR Comments at 7-9; R Street November 21 ANOPR Comments at 1; \nSouth Dakota Commission November 13 ANOPR Comments at 5; Talen December 5 \nANOPR Reply Comments at 7.  \n284 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."},{"page":78,"startToken":31605,"endToken":32056,"text":"Docket No. EL26-69-000 \n- 78 - \nAdditionally, as part of this informational report, we direct NYISO to identify any \nongoing stakeholder processes that aim to increase the pace of adding generating capacity \nin the NYISO region.  The informational report must include a detailed schedule of such \ninitiatives, including timing of the stakeholder process and dates of any anticipated filings \nwith the Commission.   \nIV. \nBriefing Questions \n130. 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 NYISO and the Transmission Owners, in responding to the order \nto show cause, should protect existing commercial arrangements including:  (1) what \nwould be a reasonable implementation period to ensure minimal disruption to such \nexisting commercial arrangements, and (2) how to allow a reasonable amount of time to \nfinalize ongoing agreements that are nearing completion as of the date such Tariff \nprovisions are filed with the Commission. \n131. 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 \nNYISO’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 \npreference to take the new transmission services, including potential uncertainties around \nthe type, location, and quantity of such expected loads?     \n132. Today’s order preliminarily finds that NYISO’s Tariff appears to be unjust and \nunreasonable without the inclusion of cost shifting protections.  We find that there may \nbe a variety of possible approaches to protect customers from significant cost shifts \nassociated with Network Upgrades triggered by large loads.  To that end, we direct \nrespondents to include information regarding potential structures for agreements between \nthe transmission owner/provider and an Eligible Customer to prevent unjust and \nunreasonable cost shifts among transmission customers related to Network Upgrade costs \nrequired for large loads.  Further, please include information on what an appropriate"},{"page":79,"startToken":32056,"endToken":32462,"text":"Docket No. EL26-69-000 \n- 79 - \nminimum level of cost recovery and financial security from an Eligible Customer would \nbe under any such agreements. \n133. Today’s order preliminarily finds that NYISO’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 NYISO to explain whether the \nTariff remains just and reasonable without provisions that (1) require the evaluation of \nalternative transmission technologies in transmission service request studies, using \nmodels that are capable of evaluating the transmission system to accurately account for \nadvanced transmission technologies, in all instances, without the need for a request from \nthe Eligible Customer seeking transmission service on behalf of large load; and (2) if \ntraditional Network Upgrades are selected instead of alternative transmission \ntechnologies, inclusion in the study report to the Eligible Customer seeking transmission \nservice on behalf of large load of a sufficiently clear demonstration of why alternative \ntransmission technologies are not feasible (i.e., would not resolve reliability violations \nidentified or meet the relevant planning criteria) or would not result in lower costs or a \nfaster timeline for accommodating the transmission service request.  As noted above, to \nthe extent stakeholders believe that specific characteristics of providing transmission \nservice to Eligible Customers on behalf of large loads warrant requirements beyond those \ncontemplated here, we seek further briefing.  \n134. Today’s order preliminarily finds that NYISO’s Tariff appears to be unjust and \nunreasonable because it does not contain provisions allowing an interconnection \ncustomer serving electrically proximate large load or large co-located load to seek \ngenerator interconnection service(s) that reflects the operational dynamics of serving such \nloads.  Any filings or tariff changes submitted in response to this order should address the \nfollowing questions:  \na. To what extent would NYISO allow an interconnection customer’s \ngenerating facility serving electrically proximate large load or large co-\nlocated load to participate in NYISO’s energy and ancillary services \nmarket, and if NYISO were to allow them to participate, what restrictions \nor mitigation would NYISO apply? \nb. To the extent that NYISO 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 NYISO account \nfor the generating facilities serving electrically proximate large load or \nlarge co-located load in the resource adequacy construct?  If applicable, \nwould NYISO allow the generating facilities serving electrically proximate \nlarge load or large co-located load to participate in NYISO’s capacity"},{"page":80,"startToken":32462,"endToken":32889,"text":"Docket No. EL26-69-000 \n- 80 - \nmarket?  If so, would NYISO accredit these generating facilities using the \nsame method as other NYISO 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. EL26-69-000 as discussed in the body of this order. \n(B) \nNYISO and the Transmission Owners are hereby directed, within 60 days \nof the date of the order, either:  (1) to show cause as to why the Tariff remains just and \nreasonable and not unduly discriminatory or preferential; or (2) to explain what changes \nto the Tariff they believe would remedy the identified concerns if the Commission were \nto determine that the Tariff has in fact become unjust and unreasonable or unduly \ndiscriminatory or preferential and, therefore, proceeds to establish a replacement Tariff. \n(C) \nNYISO 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. EL26-69-000 \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 \ncourier) delivery to Federal Energy Regulatory Commission, 12225  Wilkins Avenue, \nRockville, MD  20852. \n(E) \nInterested entities may respond within 30 days of NYISO’s and the \nTransmission Owners’ filing, addressing either or both of:  (1) whether the Tariff remains \njust and reasonable and not unduly discriminatory or preferential; and (2) if not, what \nchanges to the Tariff should be implemented as a replacement rate. \n(F) \nThe Secretary shall promptly publish in the Federal Register a notice of the \nCommission’s initiation of the proceeding under section 206 of the FPA in Docket No. \nEL26-69-000."},{"page":81,"startToken":32889,"endToken":32984,"text":"Docket No. EL26-69-000 \n- 81 - \n(G) \nThe refund effective date in Docket No. EL26-69-000 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 \nCommissioner Rosner is concurring with a separate statement \nattached. \n \nCommissioner See is concurring with a separate statement attached. \n \nCommissioner Chang is concurring with a separate attached. \n \nCommissioner LaCerte is concurring with a separate statement \nattached. \n \n( S E A L ) \n \n \n \n \nCarlos D. Clay, \nDeputy Secretary."},{"page":82,"startToken":32984,"endToken":33215,"text":"Docket No. EL26-69-000 \n- 82 - \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 Corporation285 \nAmerican Public Gas Association \nAmerican Public Power Association (APPA) \nAmerican Terawatt, Inc. (American Terawatt) \nAmerican Transmission Company LLC (ATC)286 \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 \n285 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. \n286 ATC submitted comments on behalf of itself and its corporate manager ATC \nManagement Inc."},{"page":83,"startToken":33215,"endToken":33415,"text":"Docket No. EL26-69-000 \n- 83 - \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)287 \nDigital Energy Council  \nDigital Power Network \nDistributed Capacity Parties288 \nDr. Elisa Nelson \nDTE Electric Company (DTE) \nDuke Energy Corporation (Duke) \nEDF Power Solutions, Inc. (EDF Power) \nEdison Electric Institute (EEI) \nElectricity Consumers Resource Council (ELCON) \nElectricity Customers Alliance (ECA) \nElectric Power Supply Association (EPSA) \nEmerald AI (Emerald) \nEnchanted Rock, LLC \nEnergy New England, LLC \n \n287 The Illinois Attorney General joined the Joint Consumer Advocates in filing \nreply comments. \n288 Distributed Capacity Parties include:  Clovereleaf Infrastructure; Spark \nCommunity Investment d/b/a Sparkfund; and Voltus, Inc."},{"page":84,"startToken":33415,"endToken":33642,"text":"Docket No. EL26-69-000 \n- 84 - \nEnergy Trading Institute \nENGIE North America, Inc. (ENGIE) \nEntergy Services, LLC (Entergy)289 \nEnvironmental Law & Policy Center \nEolian L.P. (Eolian) \nEquinix, Inc. \nesVolta, LP \nETX Upstream, LLC \nEversource Energy290 \nExelon Corporation (Exelon)291 \nFervo Energy Company (Fervo) \nFirstEnergy Service Company292 \nFluence \nFront Door Technologies LLC \nFuelCell Energy, Inc. \nGeorgia Public Service Commission  \nGeronimo Power, LLC (Geronimo) \nGoogle LLC (Google) \nGovernors Josh Shapiro and Glenn Youngkin \nGridCARE \nGridStor LLC (GridStor) \nHarvard Electricity Law Initiative \n \n289 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. \n290 Eversource Energy submitted comments on behalf of its affiliates The \nConnecticut Light and Power Company, NSTAR Electric Company, and Public Service \nCompany of New Hampshire, and through its agent Eversource Energy Service \nCompany. \n291 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. \n292 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":85,"startToken":33642,"endToken":33953,"text":"Docket No. EL26-69-000 \n- 85 - \nHelion Energy (Helion) \nHerbert Schrayschuen \nHeron Power Electronics Company \nIndiana Energy Association \nIndicated PJM Transmission Owners293 \nIndustrial Customer Organizations (Industrial Customers)294 \nInformation Technology Industry Council \nInfrastructure Masons, Inc. (Infrastructure Masons) \nInstitute for Progress \nInternational Energy Credit Association \nInvenergy295 \n \n293 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. \n294 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 \n295 Invenergy includes:  Invenergy Wind Development North America LLC, \nInvenergy Solar Development North America LLC, and Invenergy Thermal Development \nHoldings LLC."},{"page":86,"startToken":33953,"endToken":34227,"text":"Docket No. EL26-69-000 \n- 86 - \nIron Mountain Data Centers, LLC \nISO New England, Inc. \nITC Holdings Corp. (ITC) \nJason Miller, on behalf of VEIR Inc. \nKansas Corporation Commission (Kansas Commission) \nL. Lynne Kiesling  \nL.M. Marlowe \nLand Trust Alliance \nLarge Public Power Council \nLauren Hopkins \nLEAN Energy US \nLoad Flexibility Parties296 \nLong Island Power Authority \nLongroad Energy Holdings, LLC (Longroad) \nLouisiana Public Service Commission \nLS Power Development, LLC (LS Power) \nMaine Office of the Public Advocate \nMaryland Energy Administration  \nMaryland Public Service Commission \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)297  \n \n296 Load Flexibility Parties include:  Enerwise Global Technologies, LLC d/b/a \nCPower, Enel North America, Inc., and Voltus, Inc. \n297 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"},{"page":87,"startToken":34227,"endToken":34538,"text":"Docket No. EL26-69-000 \n- 87 - \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 \nNational Association of State Utility Consumer Advocates \nNational Conference of State Legislatures (NCSL) \nNational Congress of American Indians \nNational Grid PLC (National Grid)298 \nNational Rural Electric Cooperative Association (NRECA) \nNebraska Power Review Board (Nebraska Board) \nNew England States Committee on Electricity \nNew England Conference of Public Utility Commissioners \nNew England Consumer-Owned Systems299  \nNew England Public Systems300 \n \nCompany, a Minnesota corporation, and Northern States Power Company, a Wisconsin \ncorporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric \nCompany; Otter Tail Power Company; Prairie Power, Inc.; Republic Transmission, LLC; \nSouthern Illinois Power Cooperative; Southern Indiana Gas & Electric Company (d/b/a \nCenterPoint Energy Indiana South); Southern Minnesota Municipal Power Agency; \nWabash Valley Power Association, Inc.; and Wolverine Power Supply Cooperative, Inc \n298 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. \n299 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. \n300 New England Public Systems include:  Connecticut Municipal Electric \nCooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont"},{"page":88,"startToken":34538,"endToken":34780,"text":"Docket No. EL26-69-000 \n- 88 - \nNew Mexico Public Regulation Commission (New Mexico Commission) \nNew York Independent System Operator, Inc. (NYISO) \nNew York State Department of State Utility Intervention Unit (NY UIU) \nNew York Public Service Commission (New York Commission) \nNew York State Reliability Council (NY State Reliability Council) \nNew York Transmission Owners (NYTOs)301 \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 Corporation302 \n \nPublic Power Supply Authority. \n301 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. \n302 PPL Corporation submitted comments on behalf of the PPL Companies, which"},{"page":89,"startToken":34780,"endToken":35019,"text":"Docket No. EL26-69-000 \n- 89 - \nPrime Mover Institute \nPSEG Companies (PSEG)303 \nPublic Citizen, Inc. \nPublic Interest Organizations (PIOs)304 \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)305 \nSouthern California Edison Company (Southern California Edison) \nSouthern Companies306 \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. \n303 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. \n304 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. \n305 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. \n306 Southern Companies include:  Georgia Power Company, Alabama Power \nCompany, and Mississippi Power Company."},{"page":90,"startToken":35019,"endToken":35279,"text":"Docket No. EL26-69-000 \n- 90 - \nSouthwest Power Pool Transmission Owner Group307 \nSplight Inc. (Splight) \nState Entities308 \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  \nMembers309 \nU.S. Representatives310 \nU.S. Senate Committee on Energy and Natural Resources \nU.S. Senators311 \n \n307 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. \n308 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. \n309 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking \nMember, Subcommittee on Energy). \n310 The U.S. Representatives that submitted comments include:  Suhas \nSubramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr. \n311 The U.S. Senators that submitted comments include:  Edward J. Markey,"},{"page":91,"startToken":35279,"endToken":35333,"text":"Docket No. EL26-69-000 \n- 91 - \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 \nChris Van Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard \nBlumenthal, and Adam B. Schiff."},{"page":92,"startToken":35333,"endToken":35654,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nNew York Independent System Operator, Inc.  \n \n  Docket No. EL26-69-000 \n \nCentral Hudson Gas & Electric Corporation \nConsolidated Edison Company of New York, Inc.  \nLS Power Grid New York Corporation I \nNew York State Electric & Gas Corporation  \nNew York Transco LLC \nNextEra Energy Transmission New York, Inc. \nNiagara Mohawk Power Corp.  \nOrange and Rockland Utilities, Inc. \nRochester Gas and Electric Corporation    \n \n(Issued June 18, 2026) \n \nSWETT, Chairman, concurring \n \n1. \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.     \n2. \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 \nEng. Inc., 195 FERC ¶ 61.215 (2026) (ISO-NE); Midcontinent Indep. Sys. Operator, Inc., \n195 FERC ¶ 61,212 (2026) (MISO); N.Y. Indep. Sys. Operator, Inc., 195 FERC ¶ 61,216 \n(2026) (NYISO); PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 (2026) (PJM); Sw. \nPower Pool, Inc., 195 FERC ¶ 61,213 (2026) (SPP) (collectively, Orders to Show \nCause)."},{"page":93,"startToken":35654,"endToken":36112,"text":"Docket No. EL26-69-000 \n- 2 - \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.     \n3. \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.   \n4. \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. \n5. \nFirst, the record the Commission collected in response to the challenges identified \nin the ANOPR and subsequent resulting developments indicate that an approach that \nhonors the ANOPR principles but accounts for widening regional variation may now be \nmore efficient than a one-size-fits-all rule.6  The world has changed a great deal since last \nOctober.  The ANOPR itself, including the articulated principles, appears to have shifted \nthe playing field and prompted great progress across several electric markets.  This \nchange (and the Commission’s alignment with the Secretary) is well illustrated by a \n \n3 Secretary’s Letter at 2. \n4 Id. \n5 See SEC v. Chenery Corp., 332 U.S. 194, 202-03 (1947) (“[A]n administrative \nagency must be equipped to act either by general rule or individual order.  To insist upon \none form of action to the exclusion of the other is to exalt form over necessity. . . . [T]he \nchoice made between proceeding by general rule or by individual, ad hoc litigation is one \nthat lies primarily in the informed discretion of the administrative agency.”); Wis. Gas \nCo. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985) (“It is a well-settled principle of \nadministrative law that the decision whether to proceed by rulemaking or adjudication \nlies within the broad discretion of the agency.”). \n6 “[T]he Commission may rely on ‘generic’ or ‘general’ findings of a systemic \nproblem to support imposition of an industry-wide solution.”  Interstate Nat. Gas Ass’n \nof Am. v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002) (internal citations omitted).  However, \nthe Commission “has long allowed different regional transmission organizations to \nfollow different rules, in recognition of regional variations including potential differences \nin ‘geographic size and location.’”  Cent. Hudson Gas & Elec. Corp. v. FERC, 138 F.4th \n531, 539 (D.C. Cir. 2025) (internal citations omitted)."},{"page":94,"startToken":36112,"endToken":36541,"text":"Docket No. EL26-69-000 \n- 3 - \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. \n6. \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. \n7. \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.   \n8. \nSecond, proceeding via individual show cause orders will allow the Commission \nto act more quickly than through traditional rulemaking.  Notice-and-comment \nrulemaking may not capitalize upon individual market progress prompted since October \nand would be unduly time-consuming,8 as it also inevitably would require the additional \nsteps of accommodating the regional variations of the approach we take today.  \nRulemaking efforts can be particularly inefficient when, as here, they risk incubating \nuncertainty after progress has begun, and diverting scarce stakeholder resources away \nfrom other endeavors, such as the development of market-specific reforms submitted to \nthe Commission under section 205 of the Federal Power Act (FPA).  (To be clear, we \nvery much encourage 205 submissions encapsulating the principles we articulate in the \n206s, and with all due deliberate haste.) \n \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":95,"startToken":36541,"endToken":37024,"text":"Docket No. EL26-69-000 \n- 4 - \n9. \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.   \n10. \nThe six markets together cover nearly two-thirds of load subject to Commission-\njurisdictional rates, and therefore focusing initially on those regions is a prudent first step.  \nBut I am under no illusion that the challenges discussed in today’s orders are somehow \nunique to the RTO/ISO regions.  Our actions today do not foreclose the possibility of a \nfuture rulemaking, and nor do they prevent us from acting on filings made under sections \n205 and 206 of the FPA.  I encourage transmission providers and other stakeholders \noutside RTO/ISO regions to make individual filings to address the issues we discuss \ntoday. \n \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":96,"startToken":37024,"endToken":37091,"text":"Docket No. EL26-69-000 \n- 5 - \n11. \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":97,"startToken":37091,"endToken":37432,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n  \nNew York Independent System Operator, Inc. \n \nCentral Hudson Gas & Electric Corporation \nConsolidated Edison Company of New York, Inc.  \nLS Power Grid New York Corporation I \nNew York State Electric & Gas Corporation  \nNew York Transco LLC \nNextEra Energy Transmission New York, Inc. \nNiagara Mohawk Power Corp.  \nOrange and Rockland Utilities, Inc. \nRochester Gas and Electric Corporation   \nDocket No. EL26-69-000 \n \n \n(Issued June 18, 2026) \n \nROSNER, Commissioner, concurring:  \n \n1. \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. \n2. \nToday, we are taking an important step toward addressing these challenges.  We \nare opening a dialogue with each of the six RTO/ISOs on a series of reforms that are \ntailored to address the unique reliability and affordability challenges posed by large load \ngrowth and the infrastructure buildout needed to serve dramatically growing demand.  \nInformed by the record developed in response to the Secretary of Energy’s October 2025 \nANOPR,1 and by innovative proposals that stakeholders have filed with the Commission \nunder FPA section 205, today’s orders are aimed at ensuring that the grid remains reliable \nand affordable for all customers, especially residential customers.  It is also crucial that \n \n1 U.S. Dep’t of Energy, Secretary of Energy Chris Wright, Direction that the \nCommission Initiate Rulemaking Procedures and Proposal Regarding the Interconnection \nof Large Loads Pursuant to the Secretary’s Authority Under Section 403 of the \nDepartment of Energy Organization Act (Oct. 23, 2025)."},{"page":98,"startToken":37432,"endToken":37877,"text":"Docket No. EL26-69-000 \n- 2 - \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***** \n3. \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. \n4. \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. \n5. \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 \n \n2 See Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":99,"startToken":37877,"endToken":38301,"text":"Docket No. EL26-69-000 \n- 3 - \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. \n6. \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. \n7. \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. \n8. \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. \n9. \nThe Commission’s action today also addresses speculative load interconnection \nrequests, which clog up load interconnection queues, divert resources, and distort \nforecasts.  Under current rules, data centers can (and are incentivized to) “shop around” \ntheir prospective projects with different utilities to identify the fastest and cheapest \nlocation to connect.  This wastes time and resources studying projects that are not real.  \nWorse yet, it can inflate expected load growth by modeling projects that do not \nmaterialize, leading to double counting, inaccurate market signals, and unnecessarily high \nprices for consumers.  Today, we target speculative projects by establishing escalating \nreadiness requirements for distinct phases of the study process to deter duplicative or \nspeculative requests for transmission service.  I strongly encourage RTO/ISOs to pursue \nother improvements to load forecasts, such as using objective screening criteria like \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":100,"startToken":38301,"endToken":38737,"text":"Docket No. EL26-69-000 \n- 4 - \nphysical site control, to ensure that the data used to plan the grid is as accurate as \npossible.5   \n10. \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. \n11. \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. \n12. \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. \n13. \nFinally, today’s orders embrace yet another innovation.  Load and generation need \nnot be co-located to reduce the number of Network Upgrades; in other words, literal co-\nlocation is not the only way to facilitate faster, more efficient, and more cost-effective \nconnections to the grid.  Rather, where a large load and an associated generator are \nelectrically proximate (i.e., close together) and studied together, the reliability impacts on \nthe grid may be more limited than if the load and generator are studied separately.  Just \nlike with co-location, more limited impacts on the grid mean, all else equal, fewer \nNetwork Upgrades, which makes connecting to the grid faster, more efficient, and \ncheaper for both the large load and the associated generator.  That last point is key.  To \nadd new supply to the grid, we must create incentives for “Bring Your Own New \nGeneration.”  Today’s orders make BYONG faster and more efficient.  \n \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":101,"startToken":38737,"endToken":39183,"text":"Docket No. EL26-69-000 \n- 5 - \n14. \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***** \n15. \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. \n16. \nToday’s orders begin an important dialogue with RTO/ISOs.  As a potential next \nstep, today’s orders invite RTO/ISOs to respond by submitting proposals under FPA \nsection 205.  I cannot encourage this enough.  I also encourage public utilities outside of \nRTO/ISOs across the country to do the same.  The electric industry is rapidly evolving \nwith regions experiencing and addressing these challenges in different ways.  Many of \nthe examples on which the actions in today’s orders are based on stakeholders thinking \ncreatively to develop solutions, and I welcome other new, innovative, and regionally \ntailored proposals that build on the four key pillars set forth today:  (1) Protecting \nConsumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering \nInnovation.  Only by working together can we rise to the occasion and meet this once-in-\na-generation moment to deliver the reliable and affordable energy on which we all \ndepend.  It will not be easy, but I remain optimistic and look forward to the path ahead. \nFor these reasons, I respectfully concur. \n \n \n \n7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026)."},{"page":102,"startToken":39183,"endToken":39190,"text":"Docket No. EL26-69-000 \n- 6 - \n \n________________________ \nDavid Rosner \nCommissioner"},{"page":103,"startToken":39190,"endToken":39192,"text":"Figure 1"},{"page":104,"startToken":39192,"endToken":39194,"text":"Figure 2"},{"page":105,"startToken":39194,"endToken":39522,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nNew York Independent System Operator, Inc. \nCentral Hudson Gas & Electric Corporation \nConsolidated Edison Company of New York, Inc.  \nLS Power Grid New York Corporation I \nNew York State Electric & Gas Corporation  \nNew York Transco LLC \nNextEra Energy Transmission New York, Inc. \nNiagara Mohawk Power Corp.  \nOrange and Rockland Utilities, Inc. \nRochester Gas and Electric Corporation   \nDocket No. EL26-69-000 \n \n \n(Issued June 18, 2026) \n \nSEE, Commissioner, concurring:  \n \n1. \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.  \n2. \nToday, the Commission takes strong action within our jurisdictional sweep to \naddress these and other challenges that large load growth poses to the interstate \ntransmission system.  Today’s orders support both just and reasonable rates and speed to \n(reliable) power.  I’m deeply grateful for the many commenters who shared their insight \nand ideas in this action.  They let us build a record that highlights the need for clearer \nprocesses, better information, and faster analysis while our country moves new large load \nadditions online.  As we press forward in these dockets, I will be looking to continue \nbuilding on the momentum already underway across the country to craft more practical, \nregion-specific solutions that support timely action while protecting consumers.  Our \ncontinued ability to deliver reliable and affordable electricity requires nothing less."},{"page":106,"startToken":39522,"endToken":39988,"text":"Docket No. EL26-69-000 \n- 2 - \n3. \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.   \n4. \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. \n5. \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. \n6. \nSecond, affordability must be at the forefront as we protect consumers from \nunnecessary costs in a time of rising demand.  True, the Commission lacks authority over \nall the factors that drive electricity costs at the retail level.  Today’s orders recognize that.  \nIn response, the orders strive to aid the States in their front-line affordability duties by \ngetting into their hands all relevant information about Commission-jurisdictional costs.  \nAs these matters move forward, I am particularly interested in continued feedback from \nthe States on what information they most need to assess cost implications as new loads \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":107,"startToken":39988,"endToken":40492,"text":"Docket No. EL26-69-000 \n- 3 - \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. \n7. \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.    \n8. \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.    \n9. \nI am also sensitive to novel questions about cost shifting that interconnecting large \nload may present.  Today’s findings on cost recovery agreements between transmission \nowners and Eligible Customers are an important step in mitigating the risks of stranded \nassets if large loads prove speculative.  We are also reducing unnecessary redundancy by \nallowing an Eligible Customer to meet its financial security requirements by relying on \ncredit support or other financial security a large load customer may have posted under a \nretail agreement.  As we gain more experience studying transmission service requests on \nbehalf of large loads, it may become appropriate to further streamline financial security \narrangements.  Perhaps, for instance, cost -recovery agreements between a transmission"},{"page":108,"startToken":40492,"endToken":40759,"text":"Docket No. EL26-69-000 \n- 4 - \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)   \n10. \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 \n3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026). \n4 See id. P 456."},{"page":109,"startToken":40759,"endToken":41051,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nNew York Independent System Operator, Inc. \nCentral Hudson Gas & Electric Corporation \nConsolidated Edison Company of New York, Inc.  \nLS Power Grid New York Corporation I \nNew York State Electric & Gas Corporation  \nNew York Transco LLC \nNextEra Energy Transmission New York, Inc. \nNiagara Mohawk Power Corp.  \nOrange and Rockland Utilities, Inc. \nRochester Gas and Electric Corporation   \nDocket No. EL26-69-000 \n \n \n(Issued June 18, 2026) \n \nCHANG, Commissioner, concurring: \n \n1. \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 \n2. \nIn each of today’s orders to show cause, the Commission identifies a series of \nissues raised by the ongoing growth of large loads, directs briefing on whether existing \ntariffs remain just and reasonable in light of those developments, and describes possible \nsolutions to those issues if the Commission ultimately concludes that the relevant tariffs \nare unjust and unreasonable.  Each order is directed to a specific RTO/ISO and relevant \ntransmission owners that play a role in interconnecting large loads to the Commission-\njurisdictional transmission system.  The Commission does not pursue the broad assertion \nof jurisdictional authority contemplated in the Advanced Notice of Proposed"},{"page":110,"startToken":41051,"endToken":41509,"text":"Docket No. EL26-69-000 \n- 2 - \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   \n3. \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   \n4. \nI first want to emphasize that the Commission needs active participation from \ninterested stakeholders to develop thorough records in each region.  The Commission \ncannot make reasoned decisions about whether reforms might be needed without an \naccurate understanding of the existing processes, which differ by region.  Because the \nCommission is acting via FPA section 206 rather than generically through a rulemaking, \nthe issues addressed by these orders will be subject to ex parte restrictions across the \nRTOs/ISO regions, including with our state colleagues whose regulation can and will \ndirectly affect the individual transmission owners that need to comply with the orders \nissued today.  This will limit the Commission’s ability to engage in informal fact-finding \nand discussions with regional stakeholders, and thus, it is even more essential that the \nrecord in each region fully reflects the views of all interested parties.   \n5. \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 \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":111,"startToken":41509,"endToken":41950,"text":"Docket No. EL26-69-000 \n- 3 - \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  \n6. \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.  \n7. \nIn today’s orders, the Commission launches an inquiry into whether existing \nRTO/ISO tariffs include adequate mechanisms to mitigate the risk of undue cost shifting \namong transmission customers.  To address this risk, the Commission preliminarily \nidentifies a two-part solution: (1) that each RTO/ISO post public information about the \namount of new large loads seeking to connect to the RTO’s/ISO’s transmission system, \nany Network Upgrades identified in the local transmission planning process to serve \nthose loads, and the costs of those Network Upgrades; and (2) that each RTO/ISO adopt a \npro forma cost recovery agreement to help ensure that Eligible Customers serving large \nloads bear the risk and are ultimately responsible for costs incurred to provide \ntransmission service.  I strongly support this effort to provide additional transparency \nregarding jurisdictional transmission service requests and the costs associated with \nproviding transmission service to the requesting parties, as the Commission cannot \neffectively execute its statutory responsibilities without sufficient understanding of the \ncosts that feed into jurisdictional rates.   \n8. \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 \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":112,"startToken":41950,"endToken":42371,"text":"Docket No. EL26-69-000 \n- 4 - \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   \n9. \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 \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":113,"startToken":42371,"endToken":42799,"text":"Docket No. EL26-69-000 \n- 5 - \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 \n10. \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.   \n11. \nThe Commission’s experience in the PJM co-location proceeding highlights the \ncomplexities and challenges of introducing these new transmission services, which have \nsignificant ramifications for system operations, transmission planning, grid reliability, \nmarket dispatch, resource adequacy, and cost allocation.  As the Commission considers \nwhether to expand these transmission services to new types of load and new regions, I \nencourage commenters to address what impacts the introduction of new firm and non-\nfirm transmission products would have in their regions, as well as any relevant \ncharacteristics that might distinguish their regions from the Commission’s findings in the \nPJM co-location docket.  Ultimately, this topic will have direct long-term impacts on how \nfuture transmission systems will be planned and configured, how efficiently future power \nmarkets will operate, and how customers will respond to prices and system needs.  \nTherefore, I am specifically interested in understanding how extending the new \ntransmission services might affect individual suppliers or customers, as well as how \nexisting systems or processes might be affected by these new services.  I am open to \nunderstanding how these services might be helpful to a region or that they may create \nproblems not yet anticipated."},{"page":114,"startToken":42799,"endToken":43202,"text":"Docket No. EL26-69-000 \n- 6 - \nV. \nThe Orders Recognize the Importance of Evaluating Advanced Transmission \nTechnologies \n12. \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. \nVI. \nConclusion \n13. \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 \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":115,"startToken":43202,"endToken":43286,"text":"Docket No. EL26-69-000 \n- 7 - \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":116,"startToken":43286,"endToken":43615,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nNew York Independent System Operator, Inc. \nCentral Hudson Gas & Electric Corporation \nConsolidated Edison Company of New York, Inc.  \nLS Power Grid New York Corporation I \nNew York State Electric & Gas Corporation  \nNew York Transco LLC \nNextEra Energy Transmission New York, Inc. \nNiagara Mohawk Power Corp.  \nOrange and Rockland Utilities, Inc. \nRochester Gas and Electric Corporation   \nDocket No. EL26-69-000 \n \n \n(Issued June 18, 2026) \n \nLACERTE, Commissioner, concurring: \n \n1. \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 NYISO’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 NYISO, to timely submit their robust, thoughtful, and region-specific \nproposals to address the concerns that we have preliminarily identified in their respective \ntariffs and agreements.  By harnessing your region-specific expertise and creativity to \nbring tailored solutions to the table, together we can efficiently, reliably, and affordably \nintegrate large load, co-located load and generation and/or storage, as well as electrically \nproximate large load onto the transmission system.  I also support the use of alternative \ntransmission technologies to unlock every megawatt of existing capacity from our current \ntransmission system.  We have the technology.  We should use it now to enable faster \ninterconnection of large loads, lower costs to customers, and help prevent cost shifting. \n \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":117,"startToken":43615,"endToken":44096,"text":"Docket No. EL26-69-000 \n- 2 - \n2. \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 NYISO 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.   \n3.  \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 NYISO, may be unjust and unreasonable and/or unduly discriminatory or \npreferential because they lack features necessary to timely, reliably, and safely \ninterconnect and serve new large loads in a way that produces just and reasonable rates. \n4. \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 \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":118,"startToken":44096,"endToken":44595,"text":"Docket No. EL26-69-000 \n- 3 - \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.   \n5. \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, NYISO, 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.   \n6. \nThis is not a time to be cavalier and dodge the urgent need to meet the moment.  \nWhile this is a long journey, even so, we must continue to move at breakneck pace to win  \nthe AI race.  So let me be direct.  If you choose not to submit timely, reasonable, non-\ndiscriminatory or preferential, comprehensive, and substantiated proposal(s), as directed \nand as required under our applicable statutes, your deficient response will not go \nunnoticed.  I am prepared to play jurisdictional hardball, if needed.6  This Commission \n \n5 See, e.g., NRG Power Mktg, LLC v. FERC, 862 FERC 108, 105 (D.C. Cir. 2017) \n(FERC may not employ a rate design that follows “a completely different strategy” than, \nor is “methodologically distinct” from, a proposed rate) (internal quotations omitted); \nOxy USA, Inc. v. FERC, 64 F.3d 679, 692 (D.C. Cir. 1995) (stating that a proposal under \nFPA section 205 “need not be the only reasonable methodology, or even the most \naccurate”); City of Winnfield v. FERC, 744 F.2d 871, at 874-875 (D.C. Cir. 1984) \n(comparing the respective authorities of the Commission and public utilities under \nsections 205 and 206). \n6 16 U.S.C. § 824(b); New York v. FERC, 535 U.S. 17 (2002) (“There is no \nlanguage in the statute limiting FERC’s transmission jurisdiction to the wholesale \nmarket[.]”)) (emphasis in original); id. at 20 (stating that “the FPA authorizes FERC's"},{"page":119,"startToken":44595,"endToken":44897,"text":"Docket No. EL26-69-000 \n- 4 - \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 NYISO 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.  \n7. \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. \n8. \nFor these reasons, I respectfully concur. \n \n \n______________________________ \nDavid LaCerte \nCommissioner \n \n \n \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":3249,"startToken":0,"endToken":270},{"p":2,"at":3249,"title":"D. Extending New Transmission Services to Eligible Customers Taking Service on","method":"printed heading","endPage":2,"endAt":3448,"startToken":270,"endToken":287},{"p":2,"at":3448,"title":"E. 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