{"document":{"slug":"e-10-caiso-el26-71-000","title":"CAISO show cause order","issued":"2026-06-18","docket":"EL26-71-000","filer":"FERC","group":"June 18 orders","kind":"order","file":"docs/orders/e-10-caiso-el26-71-000.pdf","url":"https://www.ferc.gov/media/e-10-el26-71-000","sha256":"6a01f45e89c07fe1ccdc21742b1ea73c32b1e81a4710040728c9134201ec8d74","pages":118,"tokens":43959,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":148,"text":"195 FERC ¶ 61,214 \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 \nCalifornia Independent System Operator Corporation \nCitizen S-Line Transmission LLC \nCitizens Sunrise Transmission LLC \nCitizens Sycamore-Penasquitos Transmission LLC \nCity of Anaheim, California \nCity of Azusa, California \nCity of Banning, California \nCity of Colton, California \nCity of Pasadena, California \nCity of Riverside, California \nDCR Transmission, L.L.C. \nDesertLink, LLC \nGridLiance West LLC \nHorizon West Transmission, LLC \nLS Power Grid California, LLC \nMorongo Transmission LLC \nPacific Gas and Electric Company \nSan Diego Gas & Electric Company \nSouthern California Edison Company \nStartrans IO, L.L.C. \nSunZia Transmission, LLC \nTrans Bay Cable LLC \nValley Electric Association, Inc. \nViridon Path 15, LLC \nWestern Area Power Administration \nDocket No.\n \nEL26-71-000 \n \n \n \nORDER INSTITUTING PROCEEDING \nUNDER SECTION 206 OF THE FEDERAL POWER ACT \n \n(Issued June 18, 2026)"},{"page":2,"startToken":148,"endToken":324,"text":"Docket No. EL26-71-000 \n- 2 - \n \nParagraph Numbers \nI. Background ..................................................................................................................... 6. \nA. Growth of Large and Co-Located Loads and ANOPR ............................................. 6. \nB. Recent Proceedings Addressing Large and Co-Located Loads .............................. 11. \n1. PJM Co-Location Proceedings ............................................................................ 12. \n2. SPP High Impact Large Load and High Impact Large Load Generation \nAssessment Process ................................................................................................. 15. \n3. SPP Conditional High Impact Large Load Service ............................................. 17. \nII. CAISO’s Existing Processes ........................................................................................ 19. \nA. Existing Tariff Processes ......................................................................................... 19. \nB. Recent Stakeholder Proceedings in CAISO ............................................................ 28. \nIII. Discussion ................................................................................................................... 31. \nA. Transmission Service to Eligible Customers on Behalf of Large Loads ................ 38. \n1. Jurisdiction ........................................................................................................... 41. \n2. Tariff Provisions .................................................................................................. 48. \nB. Cost Shifting Risk Among Transmission Customers .............................................. 65. \n1. Jurisdiction ........................................................................................................... 67. \n2. Additional Cost Transparency ............................................................................. 70. \n3. Cost Recovery Agreements ................................................................................. 76. \nC. Co-Location Arrangements and Load with Behind the Meter Generation ............. 85. \n1. Definition ............................................................................................................. 87. \n2. Jurisdiction ........................................................................................................... 91. \n3. Tariff Provisions .................................................................................................. 93. \nD. Extending New Transmission Services to Eligible Customers Taking Service on \nBehalf of Flexible Large Loads ................................................................................. 103. \nE. Interconnection Customers Serving Electrically Proximate Large Load and Co-\nLocated Load .............................................................................................................. 106. \nF. Informational Report .............................................................................................. 120. \nIV. Briefing Questions .................................................................................................... 123."},{"page":3,"startToken":324,"endToken":799,"text":"Docket No. EL26-71-000 \n- 3 - \n \nOver the past year, the Commission has taken action in numerous dockets1 to \naddress issues related to (a) unprecedented increases in requests for transmission service \nto serve large loads2 and (b) growing interest in the co-location of loads with generating \nfacilities (co-location arrangements3). Separately, the Secretary of Energy (Secretary) \nreleased an advance notice of proposed rulemaking (ANOPR) in October 2025. The \nANOPR, issued pursuant to section 403 of the Department of Energy Organization Act,4 \ndirected the Commission to consider taking additional actions to address the addition of \nlarge and co-located loads to the transmission system.5 The records in these proceedings \nillustrate a host of urgent challenges associated with providing the transmission service \nneeded to serve the ongoing influx of large loads while maintaining reliability and \naffordability. In particular, stakeholders have expressed concerns that large loads are not \nefficiently and appropriately integrated onto the transmission system; have identified a \n \n1 See, e.g., PJM Interconnection, L.L.C., 190 FERC ¶ 61,115 (2025) (PJM Show \nCause Order); PJM Interconnection, L.L.C., 193 FERC ¶ 61,217 (2025) (PJM Co-\nLocation Order); Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026) (SPP HILL Order); \nSw. Power Pool, Inc., 195 FERC ¶ 61,196 (2026) (SPP CHILLS Order); see also, e.g., \nDuke Energy Carolinas, LLC, 193 FERC ¶ 61,237 (2025); Commonwealth Edison Co., \n194 FERC ¶ 61,181 (2026). \n2 As explained below, it appears that it would be reasonable to define a large load \nas (1) a new commercial or industrial customer, (2) located at a single site behind one or \nmore points of interconnection, (3) that has a peak load of 50 MW or greater, (4) \ninterconnects to the transmission system at a voltage level of greater than 69 kV, and (5) \nis not part of a co-location arrangement. See infra P 57. \n3 As explained below, it appears that it would be reasonable to define co-located \nload as a configuration that refers to end-use customer load that is physically connected \nto the facilities of an existing or planned generating facility on the interconnection \ncustomer’s side of the point of interconnection to the RTO/ISO’s transmission system. \nIn this order, we will use the term co-location arrangement when referring to both the \nco-located load and the associated generating facility. See infra P 88. \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":799,"endToken":1280,"text":"Docket No. EL26-71-000 \n- 4 - \nnumber of unique challenges that large load integration poses for the reliable operation of \nthat system; and have debated how best to ensure that the rates, terms, and conditions of \ntransmission service remain just and reasonable as more and more large loads are \nonboarded onto that system.6 The records in these proceedings likewise present serious \nconcerns about the lack of clarity and consistency in Regional Transmission Organization \nor Independent System Operator (RTO/ISO) tariffs—including with respect to the rates, \nterms, and conditions of service that apply to flexible large loads, co-location \narrangements, load with behind the meter generation, and generating facilities with \nelectrically proximate large load7 or co-located load. \n \nThe findings in several recent Commission proceedings establish the foundations \nof a just and reasonable framework for addressing these concerns and ensuring the \ntimely, efficient, and reliable integration of large and co-located loads onto the \ntransmission system. For example, Southwest Power Pool, Inc. (SPP) has recently taken \na number of innovative and proactive steps to address the challenges of integrating large \nloads, co-located loads, and/or generation and electrically proximate large load onto the \ntransmission system while ensuring that its tariff remains just and reasonable, and PJM \nInterconnection, L.L.C. (PJM) has likewise taken steps toward that goal in response to \nthis Commission’s directives.8 By contrast, in the California Independent System \nOperator Corporation (CAISO) region, neither CAISO nor a significant number of the \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. EL26-71-000. \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 112. \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":1280,"endToken":1695,"text":"Docket No. EL26-71-000 \n- 5 - \nParticipating Transmission Owners9 have filed proposals to address the challenges \nassociated with the integration of large and co-located loads.10 \n \nAs discussed below, we find that CAISO’s existing Open Access Transmission \nTariff (Tariff) and/or the Transmission Owner Tariffs (TO Tariffs) of the Participating \nTransmission Owners appear 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),11 and we direct CAISO and the Participating Transmission \nOwners, within 60 days of the date of this order, to either: \n(1) show cause as to why their tariffs remain 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 Participating Transmission Owners refers to the entities listed in the caption of \nthis order. Although DATC Path 15, LLC is listed as a signatory to the Transmission \nControl Agreement in CAISO’s Tariff, Viridon Path 15 LLC succeeded DATC Path 15, \nLLC on March 28, 2025. We recognize the Participating Transmission Owners include \nentities that are not subject to the Commission’s jurisdiction because they are not public \nutilities pursuant to section 201(f) of the FPA. See 16 U.S.C. § 824(f); City of Anaheim, \n171 FERC ¶ 61,263, at PP 19-22 (2020). Although the Commission retains the authority \nto review those entities’ formula rates to ensure that CAISO’s rates remain just and \nreasonable, we acknowledge that those entities are not subject to the Commission’s \njurisdiction over public utilities pursuant to section 201(f) of the FPA. However, we have \nincluded them here because their Transmission Owner Tariffs on file with the \nCommission detail the wholesale load interconnection process in CAISO. If a non-public \nutility wishes to be removed from this proceeding, we will rescind the show cause order \nagainst them at their request, and we expect CAISO to respond to this order regarding the \nnon-public utility’s CAISO Tariff provisions on file with the Commission. See Sw. \nPower Pool, Inc., 180 FERC ¶ 61,022, at P 40 (2022). \n10 We note that certain Participating Transmission Owners have made filings \nrelated to these challenges. See, e.g., GridLiance West LLC, Filing, Docket No. \nER26-2272-000 (filed Apr. 21, 2026) (proposing tariff revisions to extend its existing \ninterconnection procedures to end-use customers). \n11 16 U.S.C. § 824e. \n12 CAISO’s Tariff defines Eligible Customer as:"},{"page":6,"startToken":1695,"endToken":2078,"text":"Docket No. EL26-71-000 \n- 6 - \n(b) additional transparency concerning the network upgrade13 costs to \nprovide transmission service to Eligible Customers on behalf of large loads; \nand a pro forma cost recovery agreement between CAISO, 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 \n(i) any utility (including Participating [Transmission Owners], \nMarket Participants and any power marketer), federal power \nmarketing agency, or any person generating Energy for sale \nor resale . . . ; and (ii) any retail customer taking unbundled \ntransmission service pursuant to a state retail access program \nor pursuant to a voluntary offer of unbundled retail \ntransmission service by the Participating [Transmission \nOwner]. \nCAISO, CAISO eTariff, app. A (Definitions), Eligible Customer (1.0.0) (CAISO Tariff). \nHowever, under the CAISO Tariff, Scheduling Coordinators must identify the Eligible \nCustomers they represent. Id. § 4.5.2 (Eligible Customers and Convergence Bidding \nEntities) (1.0.0), 4.5.2.1. Therefore, as CAISO explains and as discussed below, demand \nis met through the market participation of Scheduling Coordinators. CAISO, Large Load \nConsiderations Issue Paper 11 (Jan. 30, 2026), https://www.caiso.com/documents/issue-\npaper-large-load-consideration-jan-20-2026.pdf (CAISO Large Load Issue Paper). \n13 The term network upgrades is used throughout this order to refer to \nmodifications or additions to transmission-related facilities that are integrated with and \nsupport the overall transmission system. See pro forma OATT § 1.27 (Definitions – \nNetwork Upgrades). We note that CAISO’s definition of Network Upgrades applies only \nto additions, modifications, and upgrades required to accommodate the interconnection of \ngenerating facilities. See CAISO Tariff, app. A (Definitions), Network Upgrades (0.0.0). \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"},{"page":7,"startToken":2078,"endToken":2451,"text":"Docket No. EL26-71-000 \n- 7 - \n(e) the rates, terms, and conditions of service applicable to interconnection \ncustomers serving electrically proximate large load or co-located load; or \n(2) explain what changes to their tariffs would remedy the identified concerns if \nthe Commission were to determine that the tariffs have in fact become unjust and \nunreasonable or unduly discriminatory or preferential and, therefore, proceeds to \nestablish a replacement tariff. \n \nWe are also concerned with CAISO’s need to ensure adequate generation to serve \nnew large loads.15 We therefore direct CAISO to submit, within 30 days of the date of \nissuance of this order, an informational report on how CAISO intends to ensure that \nadequate generation will be available to serve existing and new large loads, as detailed \nlater in this order. \n \nWe recognize that large loads, including data centers, are actively working with \ntransmission owners and other relevant entities to interconnect to, and to take service \nfrom, the transmission system. We appreciate that different large loads are currently at \ndifferent stages of that process. We also understand that large loads and Eligible \nCustomers taking transmission service on behalf of large loads are negotiating, entering \ninto, and/or have executed various agreements related to interconnecting to the \ntransmission system and/or the provision of transmission service. This proceeding is not \nintended to disrupt existing commercial arrangements, but rather to establish prospective \nreforms. Accordingly, any tariff revisions offered by CAISO and/or the Participating \nTransmission Owners in response to this proceeding should (a) propose a reasonable \nimplementation period to ensure minimal disruption to such existing commercial \narrangements, and (b) allow a reasonable amount of time to finalize ongoing agreements \nthat are nearing completion as of the date such tariff provisions are filed with the \nCommission. Such proposed tariff revisions should include a reasonable effective date \nthat accommodates such considerations regarding these existing commercial \narrangements. \n \nwilling and able to limit their energy withdrawals from the transmission system under \ncertain conditions. See infra note 218. \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)."},{"page":8,"startToken":2451,"endToken":2867,"text":"Docket No. EL26-71-000 \n- 8 - \nI. \nBackground \nA. \nGrowth of Large and Co-Located Loads and ANOPR \n \nAs the Secretary explained in the ANOPR, electricity demand in the United States \nis expected to grow at an extraordinary pace in the near term, largely due to the rapid \ngrowth of large loads.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 \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 \n \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 \n \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). \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)."},{"page":9,"startToken":2867,"endToken":3197,"text":"Docket No. EL26-71-000 \n- 9 - \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 \n \nCAISO’s comments in response to the ANOPR recognize the growth of large \nloads and highlight the challenges that the integration of large loads poses to transmission \nsystem operations given those loads’ size, operational behavior, and unique potential to \nimpact the transmission system.23 A number of large load projects are underway in the \nCAISO footprint. Those projects have been driven by a number of factors, including data \ncenter development, electric vehicle charging, and electrification of agricultural and \nindustrial processes, among others.24 Further, as of January 2026, the California Energy \nCommission forecasts data center load in the CAISO balancing authority area to increase \nby 1.8 GW by 2030 and 4.9 GW by 2040.25 PG&E indicates that by the end of 2024, the \nmegawatts attributable to large load customers in its region who were requesting \ntransmission-level interconnections exceeded existing transmission-level customers’ \nmegawatts by 4,000%.26 Southern California Edison also notes that it has seen an \nincrease in data centers in its service territory.27 \n \n20 Id. P 2. \n21 Id. (citing PJM Co-Location Order, 193 FERC ¶ 61,217; SPP HILL Order, 194 \nFERC ¶ 61,031; Commonwealth Edison Co., 194 FERC ¶ 61,181; Tri-State Generation \n& Transmission Ass’n, 193 FERC ¶ 61,070 (2025); Duke Energy Carolinas, LLC, 193 \nFERC ¶ 61,237). \n22 Id. PP 3-4. \n23 CAISO November 21 ANOPR Comments at 3-4; see also CAISO Large Load \nIssue Paper at 13-14; Southern California Edison December 5 ANOPR Comments at 3-4 \n(noting concern about reliability and resource adequacy challenges due to large load \nadditions). \n24 CAISO Large Load Issue Paper at 3. \n25 Id. at 8. \n26 PG&E November 21 ANOPR Comments at 3. \n27 Southern California Edison December 5 ANOPR Comments at 3."},{"page":10,"startToken":3197,"endToken":3576,"text":"Docket No. EL26-71-000 \n- 10 - \n \nWhile CPUC asserts that issues related to large and co-located load integration are \nbetter addressed at the state level in CAISO,28 and PG&E asserts that CAISO’s existing \nprocesses work well,29 many entities in CAISO suggest that additional reform is needed. \nCAISO and PG&E generally support standardized study process requirements, as \ncontemplated in the ANOPR with accommodation for regional variations, for large loads \nand co-location arrangements.30 CAISO also supports establishing operational and \ninformation sharing requirements for large loads to ensure reliability and help prevent \ncost shifting.31 CAISO likewise supports efforts to ensure that co-located loads pay for \nancillary services from which they benefit.32 CAISO and California DWR note the \nbenefit of encouraging flexible or curtailable loads to help avoid unnecessary network \nupgrades or new generation.33 California DWR also raises concerns about cost shifting \nwhere network upgrades are built to support large load additions that do not materialize \nas planned.34 CPUC supports additional transparency related to the addition of large \nloads, particularly for the costs of network upgrades associated with large load \nadditions.35 \n \nMoreover, many commenters in the ANOPR proceeding filed persuasive \ncomments documenting, generally, the need for clear and consistent tariff provisions to \n \n28 See generally CPUC November 21 ANOPR Comments at 1-4; see also PG&E \nNovember 21 ANOPR Comments at 3-7 (detailing and explaining the advantages of \nPG&E’s state-level rules). \n29 PG&E November 21 ANOPR Comments at 12. \n30 CAISO November 21 ANOPR Comments at 7-8; PG&E November 21 ANOPR \nComments at 14 (noting that standardized requirements could be effective to address \nspeculative projects and provide transmission providers with useful information). \n31 CAISO November 21 ANOPR Comments at 9-11. \n32 Id. at 15-16. \n33 Id. at 15; California DWR November 21 ANOPR Comments at 3-6; see also \nPG&E November 21 ANOPR Comments at 16 (recognizing benefits of large and \nco-located load flexibility). \n34 California DWR November 21 ANOPR Comments at 8; see also CPUC \nNovember 21 ANOPR Comments at 16 (noting that it supports ratepayer protections and \nefforts to mitigate risk of cost shifting); Southern California Edison December 5 ANOPR \nComments at 3 (supporting protections to prevent cost shifting to other customers). \n35 CPUC December 5 ANOPR Comments at 16-19."},{"page":11,"startToken":3576,"endToken":4025,"text":"Docket No. EL26-71-000 \n- 11 - \nensure regulatory and process certainty, fairness and consistency, and efficiency as large \nand co-located loads are added to the transmission system in increasing numbers.36 \nThere is also broad support for rules that help to ensure that other transmission customers \nare not unfairly burdened with additional costs or reliability impacts as large and co-\nlocated loads interconnect to the transmission system.37 In addition, many ANOPR \ncommenters highlighted the need to efficiently integrate large loads, particularly data \ncenters, to support national security priorities and economic development.38 \nB. \nRecent Proceedings Addressing Large and Co-Located Loads \n \nOver the past year, the Commission has begun to address, both sua sponte and in \nresponse to complaints and FPA section 20539 filings, the growing use of co-location \narrangements.40 The Commission’s orders in those proceedings have addressed the need \n \n36 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nCalibrant November 21 ANOPR Comments at 1-3; CEBA November 21 ANOPR \nComments at 9-11; Constellation November 21 ANOPR Comments at 6; DCC 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. \n37 See, e.g., APPA November 21 ANOPR Comments at 6; Buckeye November 21 \nANOPR Comments at 17; Exelon November 21 ANOPR Comments at 10; Kansas \nCommission November 21 ANOPR Comments at 12; NCSL November 21 ANOPR \nComments at 1; NRECA November 21 ANOPR Comments at 8-9; NY UIU November \n21 ANOPR Comments at 3; OCC November 21 ANOPR Comments at 9; Oklo \nDecember 5 ANOPR Comments at 3; Southeast PIOs December 5 ANOPR Comments \n11-15; State Entities November 21 ANOPR Comments at 7-8; Tri-State November 21 \nANOPR Comments at 8; UCS November 21 ANOPR Comments at 9-11; U.S. \nRepresentatives November 21 ANOPR Comments at 1. \n38 See, e.g., AI Supply Chain Alliance November 21 ANOPR Comments at 2; \nDCC November 21 ANOPR Comments at 3; ECA November 21 ANOPR Comments at \n6; Geronimo November 21 ANOPR Comments at 1-2; Google November 21 ANOPR \nComments at 2-3; Verrus December 5 ANOPR Comments at 2. \n39 16 U.S.C. § 824d. \n40 See PJM Show Cause Order, 190 FERC ¶ 61,115; PJM Co-Location Order, \n193 FERC ¶ 61,217, order on reh’g, PJM Co-Location Rehearing Order, 195 FERC"},{"page":12,"startToken":4025,"endToken":4422,"text":"Docket No. EL26-71-000 \n- 12 - \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 CAISO’s Tariff and/or the TO Tariffs remain just and reasonable \nwithout similar provisions. \n1. \nPJM Co-Location Proceedings \n \nOn February 20, 2025, the Commission initiated a show cause proceeding against \nPJM and the PJM transmission owners regarding the lack of tariff provisions addressing \nwith sufficient clarity or consistency the rates, terms, and conditions of service that apply \nto co-location arrangements.41 The Commission explained when initiating that \nproceeding that the absence of such provisions may leave entities unable to determine \nwhat steps they can or must take to effectuate co-location arrangements of various \nconfigurations and how to do so in a manner that is just and reasonable.42 On 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 \n \n¶ 61,209; SPP HILL Order, 194 FERC ¶ 61,031; SPP CHILLS Order, 195 FERC ¶ \n61,196. \n41 See PJM Show Cause Order, 190 FERC ¶ 61,115. \n42 Id. P 74. The PJM Show Cause Order defined co-located load as a \n“configuration [that] refers to end-use customer load that is physically connected to the \nfacilities of an existing or planned Customer Facility on the Interconnection Customer’s \nside of the Point of Interconnection (‘POI’) to the PJM Transmission System.” Id. P 3 \nn.4."},{"page":13,"startToken":4422,"endToken":4765,"text":"Docket No. EL26-71-000 \n- 13 - \nco-located load and Eligible Customers taking transmission service on behalf of co-\nlocated load.43 \n \nSpecifically, the Commission found that the PJM tariff was unjust and \nunreasonable because there is a lack of sufficient clarity or consistency as to the rates, \nterms, and conditions of service that apply to interconnection customers serving co-\nlocated load.44 The Commission also found that PJM’s tariff was unjust and \nunreasonable because it does not include transmission services that reflect Eligible \nCustomers taking transmission service on behalf of co-located loads that are willing and \nable to limit their energy withdrawals from the transmission system under certain \nconditions.45 Additionally, the Commission found that PJM’s behind the meter \ngeneration rules were no longer just and reasonable.46 The Commission directed PJM to \nfile a compliance filing to revise its tariff: (1) to set forth specific terms and conditions \nthat an interconnection customer in PJM seeking to serve co-located load must follow in \norder to effectuate a co-location arrangement;47 (2) to require that the Eligible Customer \ntaking transmission service on behalf of co-located load takes one of three transmission \nservices: (a) network integration transmission service (NITS) or a new interim, non-firm \ntransmission service while network upgrades to provide full NITS service are constructed \n(interim NITS); (b) a new firm contract demand transmission service; or (c) a new non-\nfirm contract demand transmission service;48 (3) to revise the behind the meter generation \nrules and implement a transition process for existing behind the meter generation \nparticipants;49 and (4) to make several clarifications on how certain aspects of PJM’s \ngenerator interconnection process apply to interconnection customers seeking to serve \nco-located load.50 \n \n43 PJM Co-Location Order, 193 FERC ¶ 61,217. \n44 Id. P 176. \n45 Id. P 177. \n46 Id. P 179. \n47 Id. PP 187-192, 225-230. \n48 Id. PP 193-218. The Commission also established a paper hearing to determine \nthe just and reasonable rates, terms, and conditions for the new transmission services. Id. \nPP 219-220. \n49 Id. PP 221-224. \n50 Id. PP 161, 231-236."},{"page":14,"startToken":4765,"endToken":5162,"text":"Docket No. EL26-71-000 \n- 14 - \n \nOn June 18, 2026, concurrently with the instant order, the Commission issued an \norder modifying the discussion in the PJM Co-Location Order and setting aside the order \nin part; accepting in part and rejecting in part PJM’s compliance filing, and directing a \nfurther compliance filing; and establishing as just and reasonable certain rates, terms, and \nconditions for the new transmission services (i.e., interim NITS, firm contract demand \ntransmission service, and non-firm contract demand transmission service).51 \n2. \nSPP High Impact Large Load and High Impact Large Load \nGeneration Assessment Process \n \nOn January 14, 2026, the Commission accepted revisions to SPP’s tariff to add a \nhigh impact large load (HILL) study process and High Impact Large Load Generation \nAssessment (HILLGA) process.52 SPP’s tariff revisions established HILLs as a new \ncategory of load;53 imposed enhanced study requirements to enable SPP to assess the \nHILL’s reliability impacts on the transmission system;54 and created additional, ongoing \n \n51 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 7-9. PJM’s \ncompliance filing proposing revisions in response to the Commission’s directives \nregarding clarification that certain aspects of PJM’s generator interconnection process \napply to interconnection customers seeking to serve co-located load was accepted in part \non April 16, 2026. PJM Interconnection, L.L.C., 195 FERC ¶ 61,030 (2026). \n52 SPP HILL Order, 194 FERC ¶ 61,031 at PP 61, 64. \n53 SPP defines a HILL as: \nA new commercial or industrial load, or increase in \ncommercial or industrial load, at a single site connected \nthrough one or more shared Points of Interconnection (POIs) \nor delivery points, where such load is either (1) 10 MW or \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). \n54 SPP HILL Order, 194 FERC ¶ 61,031 at PP 13-17 (explaining that the HILL \nprocess requires up to three additional studies beyond those required of all transmission \nservice requests for transmission customers requesting to add or modify a delivery point \nassociated with a HILL, including a HILL delivery point study, HILL supplemental load"},{"page":15,"startToken":5162,"endToken":5571,"text":"Docket No. EL26-71-000 \n- 15 - \noperational requirements for transmission customers serving HILLs to ensure continued \nreliability of the transmission system.55 The tariff revisions also established the HILLGA \nprocess, a new generator interconnection service and related interconnection process to \nfacilitate the prompt interconnection of generating facilities that are specifically identified \nfor, and limited to, serving a HILL and are located no more than two substations away \nfrom the HILL.56 \n \nThe Commission stated that SPP demonstrated that the “unprecedented growth in \nlarge loads in the SPP region presents significant and unique operational and planning \nchallenges.”57 The Commission found that SPP demonstrated that its proposed HILL \nprocess was a just and reasonable approach for integrating transmission customers’ new \nlarge loads onto SPP’s transmission system in a reliable manner.58 The Commission \nfound that it was reasonable to impose additional study requirements and other proposed \nrequirements given the unique operating characteristics of HILLs. The Commission \nfurther found that the proposed study requirements would ensure the reliable integration \nof the transmission customer’s HILLs onto SPP’s transmission system and would provide \nSPP with information about their impact on SPP’s transmission system, including the \ntransmission system’s ability to withstand and control disturbances by the HILL at the \n \nconnection study, and potential supplemental Electromagnetic Transient study). \n55 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). \n56 Id. P 27 (explaining that, under the HILLGA process, SPP proposes to study \nHILLGA requests to determine whether any network upgrades are needed to \naccommodate the generating facility’s injection to the local area); id. P 32 (explaining \nthat SPP will grant HILLGA customers a new type of interconnection service, load \nlimited resource interconnection service, which grants limited interconnection service \nsolely to serve the associated HILL). \n57 Id. P 60. \n58 Id. P 61."},{"page":16,"startToken":5571,"endToken":5889,"text":"Docket No. EL26-71-000 \n- 16 - \npoint of interconnection.59 In addition, the Commission found that the proposed study \ndeposits would discourage speculative HILL study requests.60 Finally, the Commission \nconcluded that the proposed ongoing reliability requirements would allow SPP to \nmaintain reliable operation of its transmission system by increasing SPP’s visibility, \nproviding necessary data, and imposing real-time operational safeguards for HILLs.61 In \naccepting HILLGA, the Commission found that “SPP’s HILLGA process reasonably \nprovides a flexible, expedited, and separate serial interconnection process that will \nfacilitate the prompt interconnection of generating facilities that are limited to serving a \nHILL in the same local area.”62 \n3. \nSPP Conditional High Impact Large Load Service \n \nOn June 5, 2026, the Commission accepted revisions to SPP’s tariff to add a new \ntype of non-firm transmission service, conditional high impact large load service \n(CHILLS).63 CHILLS allows transmission customers serving HILLs to reliably receive \ntransfers of energy until sufficient designated resources and/or network upgrades are in \nplace to support long-term, firm transmission service.64 CHILLS is an as-available \ntransmission service that will transfer energy to designated points of delivery to serve the \nportion of a HILL eligible to receive CHILLS, subject to curtailment and interruption.65 \nCHILLS has a maximum term of seven years, which is intended to incentivize \ntransmission customers seeking CHILLS to obtain the designated resources and/or \n \n59 Id. P 62. \n60 For the HILL delivery point study, SPP required a $10,000 non-refundable \napplication fee and a $100,000 study deposit, with an additional $200,000 study deposit if \nan Electromagnetic Transient study was also required. Id. P 15. For the HILL \nsupplemental load connection study, SPP allows the host transmission owner to require a \n$25,000 study deposit. Id. P 16. \n61 Id. P 63. \n62 Id. P 64. \n63 SPP CHILLS Order, 195 FERC ¶ 61,196 at P 1. \n64 Id. P 7. \n65 Id. PP 9-10."},{"page":17,"startToken":5889,"endToken":6208,"text":"Docket No. EL26-71-000 \n- 17 - \ncomplete the network upgrades needed to procure long-term firm transmission service \nthrough existing tariff processes.66 \n \nThe Commission found that SPP had shown that unprecedented growth in large \nloads presents significant and unique operational and planning challenges.67 The \nCommission also found that SPP’s ability to add HILLs to its transmission system in a \ntimely manner may be limited due to delays in obtaining sufficient designated resources \nand completing network upgrades needed to provide long-term firm transmission service \nto such load.68 The Commission concluded that CHILLS is a just and reasonable and not \nunduly discriminatory or preferential approach to addressing the need to expeditiously \ninterconnect and provide transmission service to new HILLs, while maintaining the \nreliable operation of SPP’s transmission system.69 \nII. \nCAISO’s Existing Processes \nA. \nExisting Tariff Processes \n \nUnlike other regions, CAISO does not offer traditional Order No. 88870 network \nand point-to-point transmission services, offers no firm, long-term transmission \nreservations of capacity, and does not provide a formal application process for \ntransmission service.71 Instead, CAISO offers a single “daily” transmission service \n \n66 Id. P 9. \n67 Id. P 84. \n68 Id. \n69 Id. \n70 Promoting Wholesale Competition Through Open Access Non-Discriminatory \nTransmission Servs. by Pub. Utils.; Recovery of Stranded Costs by Pub. Utils. & \nTransmitting Utils., Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996) (cross-\nreferenced at 75 FERC ¶ 61,080), order on reh’g, Order No. 888-A, FERC Stats. & Regs. \n¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh’g, Order No. 888-B, \n81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), \naff’d in relevant part sub nom. Transmission Access Pol’y Study Grp. v. FERC, 225 F.3d \n667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). \n71 See Cal. Indep. Sys. Operator Corp., 123 FERC ¶ 61,180, at P 7 n.8 (2008) \n(CAISO)."},{"page":18,"startToken":6208,"endToken":6556,"text":"Docket No. EL26-71-000 \n- 18 - \nthat is available to all Eligible Customers on a day-to-day basis.72 All energy that is \ntransmitted under CAISO’s Tariff that is not associated with historical rights or certain \nwheeling transactions is treated as “new firm use,” and those accessing the CAISO-\ncontrolled transmission system cannot reserve transmission capacity beyond the \nday-ahead time frame.73 \n \nIn CAISO’s transmission service model, Scheduling Coordinators represent \nEligible Customers and submit bids, or self-schedules, for supply or demand for energy \nto CAISO.74 Scheduling Coordinators have equal access to all available transmission \ncapacity each day and CAISO uses the submitted bids for supply and demand to dispatch \nthe market making use of all available transmission capacity. If there is not enough \navailable transmission capacity, CAISO curtails schedules based upon Tariff-defined \nscheduling priorities.75 \n \nThe processes for studying load additions in the CAISO footprint are not detailed \nin CAISO’s Tariff. Rather, CAISO’s Participating Transmission Owners play the lead \nrole in managing the interconnection of load to the transmission system and have their \nown study processes and requirements for such interconnections.76 CAISO’s primary \nrole with respect to load additions is to account for state-projected additions of load in its \nTransmission Planning Process (TPP).77 CAISO operates under the assumption that if \ntransmission infrastructure is developed to serve new loads as contemplated in the TPP, \nthe market will reliably meet demand.78 \n \nThe TPP is conducted annually and is highly integrated with state processes and \nforecasts, including the California Energy Commission’s development of a statewide \nelectricity demand forecast and CPUC’s development of integrated resource plans.79 In \n \n72 Id. P 7. \n73 Id. \n74 CAISO Tariff, § 4.5.3 (Responsibilities of a Scheduling Coordinator) (11.0.0). \n75 See CAISO, 123 FERC ¶ 61,180 at PP 7-8; Cal. Indep. Sys. Operator Corp., \n185 FERC ¶ 61,085, at P 5 (2023). \n76 CAISO Large Load Issue Paper at 3, 5-6. \n77 Id. at 8-10. CAISO incorporates the California Energy Commission’s demand \nforecast into the TPP. \n78 Id. at 9, 11. \n79 CAISO collaborates with the California Energy Commission and CPUC on"},{"page":19,"startToken":6556,"endToken":6931,"text":"Docket No. EL26-71-000 \n- 19 - \nthe TPP, CAISO approves transmission solutions, which include new transmission \nfacilities and network upgrades or additions to existing transmission facilities, to meet \nneeds identified by CAISO.80 The TPP is conducted in three phases: In Phase 1, CAISO \ndevelops planning assumptions and a study plan; in Phase 2, CAISO completes the \ncomprehensive transmission plan; and, in Phase 3, CAISO evaluates proposals to \nconstruct and own certain network upgrades or additions.81 \n \nTo address load additions that occur after the development of the demand forecast \nand CPUC resource portfolios, the Participating Transmission Owners may propose \ntransmission solutions and network upgrades in the TPP.82 Those proposed solutions and \nnetwork upgrades must be submitted to CAISO for concurrence that the load \ninterconnection and potential network upgrades to interconnect the load meet \ntransmission reliability requirements and are consistent with the long-term transmission \nplans in the area. The Participating Transmission Owners construct and own the resulting \nnetwork upgrades.83 \n \nCosts of transmission additions or network upgrades are borne by the Participating \nTransmission Owner that will be the owner of the transmission addition or network \nupgrade, and the Participating Transmission Owner incorporates those costs into its \ntransmission revenue requirement.84 A Participating Transmission Owner’s transmission \nrevenue requirement is divided into regional (high voltage) and local (low voltage) \ncomponents that are under CAISO’s operational control.85 The Participating \n \nelectric system planning through a memorandum of understanding. See CAISO \nNovember 21 ANOPR Comments at 6-7 (citing Memorandum of Understanding Between \nCPUC and the California Energy Commission and CAISO Regarding Transmission and \nResource Planning and Implementation (Dec. 2022), \nhttps://www.caiso.com/Documents/ISO-CEC-and-CPUC-Memorandum-of-\nUnderstanding-Dec-2022.pdf). \n80 See CAISO Tariff, § 24.1 (Overview) (3.0.0). \n81 See id. § 24.2 (Nature of the Transmission Planning Process) (8.0.0). \n82 CAISO Large Load Issue Paper at 9-10. \n83 CAISO only considers the transmission aspect of solutions in the TPP. \n84 CAISO Tariff, § 24.14.2 (Cost of Needed Addition or Upgrade to be Borne by \nPTO) (0.0.0). \n85 In CAISO, low voltage facilities are considered to be under 200 kV and \ntherefore included in the local transmission revenue requirement; facilities 200 kV and \ngreater are included in the regional transmission revenue requirement. See id. app. F"},{"page":20,"startToken":6931,"endToken":7362,"text":"Docket No. EL26-71-000 \n- 20 - \nTransmission Owners recover their transmission revenue requirement through the Access \nCharge, also referred to as the Transmission Access Charge.86 The Participating \nTransmission Owners directly collect the local component of their transmission revenue \nrequirement from customers in their service area, referred to as the Local Access Charge, \nwhile the regional component of the transmission revenue requirement of every \nParticipating Transmission Owner is combined together and divided by gross load to \ndevelop a “postage stamp” rate that is assessed to all market participants volumetrically, \nknown as the Regional Access Charge. CAISO collects the Regional Access Charge and \nthen remits the monies associated with costs recovered to the Participating Transmission \nOwners.87 \n \nThe TO Tariffs include the physical interconnection process for requests to \ninterconnect wholesale load that is eligible to request interconnection under FPA section \n210(a) directly to the CAISO-controlled grid.88 While there is no pro forma TO Tariff, \nthe majority of the TO Tariffs contain similar sections regarding the interconnection \nprocess and, with limited exceptions, are structured identically. Each TO Tariff provides \nthat the Participating Transmission Owner will review interconnection applications from \neligible entities to determine whether a System Impact Study is necessary.89 If \nconducted, the System Impact Study may indicate that a Facilities Study, which the \nParticipating Transmission Owner will conduct in accordance with its TO Tariff, is \n \n(Rate Schedules) (30.0.0), § 12.1(a)(i). \n86 CAISO’s Tariff provides that “[t]he Access Charge includes the Regional \nAccess Charge and the Local Access Charge. The Access Charge will recover the \nParticipating [Transmission Owners’] Transmission Revenue Requirement in accordance \nwith Appendix F, Schedule 3.” See id. app. A (Definitions), Access Charge (1.0.0). \n87 See id. § 26.1 (Access Charges) (8.0.0). \n88 Some Participating Transmission Owners have established or proposed state-\nlevel large load-specific interconnection procedures and requirements for retail load \ninterconnecting at the distribution or transmission level. See, e.g., PG&E November 21 \nANOPR Comments at 3-7 (describing its proposed Electric Rule 30). \n89 See, e.g., Pac. Gas & Elec. Co., Transmission Owner Tariff and Related Service \nAgreements, § 10.4 (Review of Completed of Interconnection Application) (0.0.0). The \ninterconnection process in the TO Tariffs does not apply to all Eligible Customers, as \ndefined by the TO Tariff, but instead is limited to wholesale load eligible to request \ninterconnection consistent with FPA section 210(a). See, e.g., id. § 10.1 (Applicability) \n(0.0.0). All other requested interconnections are governed by the local regulatory \nauthority. Id. § 8.1 (Participating TO Obligation to Interconnection) (0.0.0)."},{"page":21,"startToken":7362,"endToken":7752,"text":"Docket No. EL26-71-000 \n- 21 - \nnecessary.90 The TO Tariffs generally do not explain the details of the study processes or \nany technical or reliability considerations included in the studies. After completion of the \nrequisite studies, the applicant and Participating Transmission Owner execute an \nInterconnection Agreement, which will include the cost responsibilities for any required \nnetwork upgrades or direct assignment facilities.91 Additionally, the TO Tariffs provide \nthat the Participating Transmission Owners will offer partial interim service if the studies \ndetermine that there is not adequate transmission capability to satisfy the full amount of \ninterconnection service requested by the applicant. In that instance, the Participating \nTransmission Owner will provide the portion of the requested interconnection service \nthat can be accommodated without any additional direct assignment facilities or \nreliability upgrades.92 Further, the TO Tariffs offer expedited interconnection procedures \nfor new network upgrades to interconnect wholesale load.93 The interconnection process \ndoes not grant transmission service; rather, the applicant must retain the services of a \nScheduling Coordinator to access transmission service over the CAISO-controlled grid.94 \nOf note, the costs of these network upgrades to effectuate load interconnection are not \nrolled into the transmission revenue requirement of the Participating Transmission Owner \nand are instead directly assigned to the Eligible Customer.95 \n \nCAISO does not have a process to evaluate load that is co-located with generating \nfacilities.96 CAISO’s Tariff sets forth generally applicable Tariff provisions regarding \n \n90 See, e.g., S. Cal. Edison Co., Transmission Owner Tariff, § 10 (Interconnection \nProcess) (15.0.0). \n91 See, e.g., Pac. Gas & Elec. Co., Transmission Owner Tariff and Related Service \nAgreements, § 8.1.2 (Costs Associated with Interconnection) (0.0.0). \n92 See, e.g., S. Cal, Edison Co., Transmission Owner Tariff § 10.10. \n93 See, e.g., id. § 10.11. \n94 See CAISO Tariff, § 2.1 (Open Access) (0.0.0). \n95 Although the TO Tariff interconnection process does not grant transmission \nservice, the network upgrades identified through the interconnection process, which are \nsubject to an interconnection agreement, may be akin to those that would be constructed \nto accommodate a transmission service request in other RTOs/ISOs; however, it is \nunclear from the TO Tariffs. \n96 See CAISO November 21 ANOPR Comments at 6 (noting that co-located retail \nloads are subject to state jurisdiction tariffs and generation is subject to the generator \ninterconnection process)."},{"page":22,"startToken":7752,"endToken":8141,"text":"Docket No. EL26-71-000 \n- 22 - \ngenerator interconnection97 and other generator interconnection procedures, including the \nGenerator Interconnection and Delivery Allocation Procedures (GIDAP)98 and the \nResource Interconnection Standards (RIS).99 The GIDAP and the RIS address CAISO’s \nprimary process for studying interconnection requests, the Queue Cluster study process. \nCAISO’s GIDAP applies to Queue Clusters 5 through 14 and consists of Phase I and \nPhase II interconnection studies that evaluate the impact of all interconnection requests \non the CAISO controlled grid and identify cost estimates for network upgrades needed to \naddress such impacts, with annual reassessments that account for changes in the \ninterconnection queue.100 CAISO’s RIS applies to Queue Cluster 15 and subsequent \nQueue Clusters and consists of: (1) a cluster study that evaluates the impact of all \ninterconnection requests on the CAISO controlled grid and identifies cost estimates for \nnetwork upgrades needed to address such impacts, (2) an annual reassessment, which \nincludes the cluster restudy, that accounts for changes in the interconnection queue, and \n(3) a clustered facilities study to specify and provide cost responsibility to implement the \nconclusions of the cluster study report and connect the interconnection facilities to the \ntransmission system.101 The GIDAP and RIS also provide processes for allocating \nTransmission Plan Deliverability (TP Deliverability).102 \n \n97 CAISO Tariff, § 25 (Interconnection of Generating Units And Facilities) (0.0.0). \n98 Id. app. DD (Generator Interconnect & Deliverability Allocation Procedure) \n(7.0.0). \n99 Id. app. KK (Resource Interconnection Standards) (0.0.0). \n100 Id. app. DD, §§ 6 (Initial Activities & Phase I of the Interconnection Study \nProcess for Queue Clusters) (22.0.0), 7 (Activities in Preparation for Phase II) (17.0.0), \n8 (Phase II Interconnection Study & TP Deliverability Allocation Processes) (22.0.0). \n101 Id. app. KK, §§ 2 (Scope and Application) (0.1.0), 2.4.3.1, 7 (Annual \nReassessment, Cluster Restudy & Activities) (1.1.0), 7.4 (Reassessment Process), \n8 (Interconnection Facilities Study & TP Deliverability) (5.0.0), 8.1.2. \n102 Under the Tariff, TP Deliverability is defined as: \nThe capability, measured in MW, of the CAISO Controlled \nGrid as modified by transmission upgrades and additions \nmodeled or identified in the annual Transmission Plan to \nsupport the interconnection with Full Capacity Deliverability \nStatus or Partial Capacity Deliverability Status of additional \nGenerating Facilities in a specified geographic or electrical \narea of the CAISO Controlled Grid."},{"page":23,"startToken":8141,"endToken":8504,"text":"Docket No. EL26-71-000 \n- 23 - \n \nPursuant to the Tariff, an interconnection customer may request a limited \noperation study to determine the extent to which the generating unit and the \ninterconnection customer’s interconnection facilities may operate prior to the completion \nof the Participating Transmission Owners’ interconnection facilities or network \nupgrades.103 CAISO and the Participating Transmission Owner may permit an \ninterconnection customer to operate its electric generating unit and interconnection \nfacilities in accordance with such studies. An interconnection customer may also request, \nand CAISO may provide, surplus interconnection service for an unneeded portion of \ninterconnection service capacity at an existing point of interconnection.104 If the \ninterconnection customer would not require a new interconnection request under the \nTariff, CAISO may study a request for surplus interconnection service as a modification \nunder section 6.7.2 of the GIDAP or RIS; otherwise, the request is studied as a new \ninterconnection request in the cluster study process.105 \nB. \nRecent Stakeholder Proceedings in CAISO \n \nIn January 2026, CAISO published an issue paper on large load considerations \nthat described CAISO’s role as it relates to large load integration and identified issues \nthat may arise in future stakeholder discussions.106 CAISO formally began a policy \ninitiative in February 2026 to consider new policies due to the emergence of large loads \nand co-located generation, including presenting the issue paper to and soliciting \n \nId. app. A (TP Deliverability) (1.0.0); see also id. app. DD, § 8 (Phase II Interconnection \nStudy & TP Deliverability Allocation Processes); id. app KK, § 8 (Interconnection \nFacilities Study & TP Deliverability), 8.9 (Allocation Process for TP Deliverability). \n103 Id. app. DD, § 14 (PTOs Interconnection Facilities and Network Upgrades) \n(12.0.0), 14.2.4; id. app. KK, § 14 (Construction and Neighboring System Impacts) \n(1.1.0), 14.2.4. \n104 Id. app. DD, § 3 (Interconnection Requests) (17.0.0), 3.4 (Surplus \nInterconnection Service); id. app. KK, § 3 (Interconnection Requests) (3.0.0), § 3.4 \n(Surplus Interconnection Service). \n105 Id. app. DD, § 6.7 (Initial Activities and Phase I of the Interconnection Study \nProcess for Queue Clusters), 6.7.2; id. app. KK, § 6 (Cluster Study Process), 6.7.2. \n106 See CAISO Large Load Issue Paper."},{"page":24,"startToken":8504,"endToken":8839,"text":"Docket No. EL26-71-000 \n- 24 - \ncomments from stakeholders.107 CAISO also held a stakeholder meeting in March 2026 \non technical requirements for large loads.108 \n \nCAISO also established an informal large load technical requirements working \ngroup in October 2025.109 That working group is comprised of Participating \nTransmission Owners with active large load interconnection requests and aims to develop \na coordinated set of technical requirements for interconnecting data center loads to the \nCAISO-controlled grid. CAISO states that the working group has been addressing topics \nrecommended by NERC, including technical requirements.110 \n \nWhile we are encouraged by CAISO’s stakeholder efforts, and by its initial \nattention to the pressing concerns associated with large and co-located loads111 and to the \nSecretary’s interest in these issues,112 we are initiating this FPA section 206 proceeding \nin order to ensure that CAISO’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 CAISO and/or the Participating \nTransmission Owners promptly propose revisions to ensure that their tariffs remain just \nand reasonable. \n \n107 See CAISO, Initiative: Large Loads, \nhttps://stakeholdercenter.caiso.com/StakeholderInitiatives/Large-loads (providing link to \npresentation and comments submitted by stakeholders). \n108 Id. \n109 CAISO Large Load Issue Paper at 13. \n110 Id. at 13-14. \n111 See Elliot Mainzer, CEO Elliot Mainzer’s Recent Congressional Testimony on \nGrid Reliability, Energy Matters Blog (Apr. 18, 2025), \nhttps://www.caiso.com/about/news/energy-matters-blog/ceo-elliot-mainzers-recent-\ncongressional-testimony-on-grid-reliability (“Currently, there is about 1 GW of data \ncenter load connected to the CAISO system. The [California Energy Commission] \nprojects an increase in data center loads over the next 15 years, with a sharp increase \nprojected to start around the 2028 timeframe. The CAISO is working diligently to serve \nemerging large electric loads within our footprint, including major enhancements to the \ntransmission system in the Silicon Valley.”). \n112 See supra PP 6-7."},{"page":25,"startToken":8839,"endToken":9174,"text":"Docket No. EL26-71-000 \n- 25 - \nIII. \nDiscussion \n \nBased on the discussion below, pursuant section 206 of the FPA, we direct CAISO \nand the Participating Transmission Owners, within 60 days of the date of this order, to \neither: \n(1) show cause as to why their tariffs remain 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 CAISO, 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 their tariffs would remedy the identified concerns if \nthe Commission were to determine that their tariffs have in fact become unjust and \nunreasonable or unduly discriminatory or preferential and, therefore, proceeds to \nestablish replacement tariffs. \n \nWe also direct CAISO to submit, within 30 days of the date of issuance of this \norder, an informational report on how CAISO intends to ensure that adequate generation \nwill be available to serve existing and new large loads. \n \nInterested entities may respond within 30 days of CAISO’s and the Participating \nTransmission Owners’ filings, addressing either or both of: (1) whether the existing"},{"page":26,"startToken":9174,"endToken":9658,"text":"Docket No. EL26-71-000 \n- 26 - \ntariffs remain just and reasonable and not unduly discriminatory or preferential; and (2) if \nnot, what changes to the tariffs should be implemented as replacement rates. \n \nWe recognize that CAISO and/or the Participating Transmission Owners (to the \nextent the matters addressed herein implicate aspects of their TO Tariffs) may elect to \naddress some or all of the issues discussed in this order by proposing revisions to their \ntariffs pursuant to their applicable FPA section 205 filing rights. We strongly encourage \nthis. Although both the Secretary’s ANOPR and our own Order Regarding Intent to Act \nexpressly recognized (and indeed encouraged) that possibility,113 no such filings were \nreceived from CAISO or the Participating Transmission Owners by the Commission prior \nto the issuance of this order. Should CAISO and/or the Participating Transmission \nOwners elect to make such filings in response to this order, those filings should state \nexplicitly that the proposals are being submitted under FPA section 205. Should CAISO \nand/or the Participating Transmission Owners submit a filing under FPA section 205, \nthey should also explain which of the Commission’s above directives their filing \naddresses and how it resolves them. Additionally, any such filing should provide a \nreasoned explanation for how the proposal will avoid disrupting existing commercial \narrangements and clearly identify a reasonable effective date that accommodates such \nexisting commercial arrangements. \n \nThe Commission will consider requests from CAISO and/or the Participating \nTransmission Owners to hold, for up to 90 days, all or certain aspects of this FPA section \n206 proceeding in abeyance, including the deadline to respond to this order. Any such \nabeyance, which will begin as of the deadline to respond to this order, would be \nconsidered to provide CAISO and the Participating Transmission Owners time while they \nwork through the applicable stakeholder processes to develop FPA section 205 filings to \nrevise their tariffs to address the issues raised in this order. Requests for a full or partial \nabeyance114 should be submitted prior to the deadline to respond to this order, \nspecifically within 45 days of issuance of this order, to allow time for the Commission to \nact on the abeyance request. We emphasize that we will not grant such abeyances \nreflexively, that any abeyance will be limited to 90 days, and that we will look with great \ndisfavor toward requests to extend the abeyance period. We anticipate that successful \nabeyance requests, if any, will include both (1) a robust description of the content of a \n \n113 See ANOPR at P 32; Order Regarding Intent to Act, 195 FERC ¶ 61,045 at P 5. \n114 A partial abeyance may be appropriate to the extent CAISO and/or \nParticipating Transmission Owners are developing FPA section 205 filings in response to \nonly a subset of the directives in this order. For any remaining directives, we expect a \nresponse to this order within the 60-day deadline set forth herein."},{"page":27,"startToken":9658,"endToken":10104,"text":"Docket No. EL26-71-000 \n- 27 - \npotential future filing under FPA section 205 and (2) a reasoned and specific explanation \nof when such a filing is expected to be made. \n \nIn cases where, as here, the Commission institutes a section 206 investigation on \nits own motion, section 206(b) of the FPA requires that the Commission establish a \nrefund effective date that is no earlier than the date of the publication by the Commission \nof notice of its intention to initiate such proceeding nor later than five months after the \npublication date. In such cases, in order to give maximum protection to customers, and \nconsistent with our precedent, we have historically tended to establish the section 206 \nrefund effective date at the earliest date allowed by section 206, and we do so here as \nwell.115 That date is the date of publication of notice of initiation of this proceeding in \nthe Federal Register. \n \nWe recognize that the framework under which CAISO provides transmission \nservice is unique among the RTOs/ISOs and that certain responsibilities fall to the \nParticipating Transmission Owners.116 We therefore expect that CAISO and the \nParticipating Transmission Owners will coordinate with each other, as appropriate, to \ndevelop responses to this order that address the concerns we identify below. \nA. \nTransmission Service to Eligible Customers on Behalf of Large Loads \n \nWe today make a preliminary finding that CAISO’s Tariff and/or the TO Tariffs \nappear to be unjust and unreasonable because they lack provisions that address, with \nsufficient clarity and consistency, how CAISO and/or the Participating Transmission \nOwners will timely study (i.e., within 60-90 days of receiving the request) the provision \nof transmission service to Eligible Customers on behalf of large loads.117 \n \nThroughout this order, we use the phrase “the provision of transmission service to \nEligible Customers on behalf of large loads” to encompass the provision of new, \nmodified, or additional jurisdictional transmission service to Eligible Customers on \nbehalf of large loads. We use this phrase broadly and recognize that in CAISO there is \n \n115 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). \n116 We recognize, for example, that under the current framework, CAISO does not \nconduct a study process for the provision of transmission service and note that the \nParticipating Transmission Owners may be able to augment their existing study processes \nfor load interconnections to respond to the Commission’s concerns. \n117 As discussed below, our findings here also apply to the study process for \nunbundled retail transmission service requests by end-use large load customers, as \nallowed by state law or voluntary utility rules."},{"page":28,"startToken":10104,"endToken":10527,"text":"Docket No. EL26-71-000 \n- 28 - \nno formal application process for transmission service and that CAISO does not offer \ntraditional Order No. 888 transmission services, as discussed above. We also recognize \nthat the Participating Transmission Owners have responsibility for wholesale load \ninterconnection studies. Thus, we understand that an Eligible Customer118 submits an \ninterconnection application to the Participating Transmission Owner, who then completes \nthe requisite studies as needed to interconnect new load. The Eligible Customer then \nmust retain the service of a Scheduling Coordinator to access the CAISO market and \nrepresent its load.119 CAISO does not appear to conduct studies to determine the \nnecessary network upgrades needed for the provision of transmission service to Eligible \nCustomers outside of the TPP.120 CAISO, however, is responsible for access to and the \nprovision of transmission service, including transmission and ancillary services, to all \nEligible Customers, and the reliability of that transmission service.121 We note that this \nphrase is not limited to instances where an Eligible Customer submits an application to \nrequest new transmission service. It also includes instances where an Eligible Customer \nrequests a new or modified point of delivery to serve a large load, where a large load \nseeks a new or modified delivery point as an unbundled retail transmission service \ncustomer, or where large loads are otherwise included in an Eligible Customer’s reported \nload growth and that Eligible Customer is taking network transmission service. \n \nWe direct CAISO and the Participating Transmission Owners, to the extent the \nmatters addressed herein implicate aspects of their respective tariffs, to explain whether \ntheir tariffs remain just and reasonable without an application process, study procedures, \nand ongoing operational requirements that address the unique characteristics and \nchallenges of providing transmission service to Eligible Customers on behalf of large \nloads, or to propose appropriate tariff revisions. \n \n118 We note, however, that under the TO Tariffs this applies only to Eligible \nCustomers who are also wholesale load eligible to request interconnection consistent with \nFPA section 210(a). E.g., Pac. Gas & Elec. Co., Transmission Owner Tariff, § 10.1. \n119 See supra P 20. \n120 See supra P 21. \n121 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,731 (“An ISO should be \nresponsible for ensuring that all users have non-discriminatory access to the transmission \nsystem and all services under ISO control. . . . [T]he ISO should be responsible for \nensuring that services (for all users, including new users) can be provided reliably, and \nfor developing and implementing policies related to curtailment to ensure the on-going \nreliability and security of the system.”)."},{"page":29,"startToken":10527,"endToken":10937,"text":"Docket No. EL26-71-000 \n- 29 - \n1. \nJurisdiction \n \nAt the outset, we clarify the principles relating to the Commission’s jurisdiction \nover the matters relevant to the integration of large loads onto the transmission system \nand the impacts of large loads on the transmission system. We recognize that rates, \nterms, and conditions associated with the addition of and service to large loads implicate \nboth federal and state interests. We also recognize that resolution of issues related to \nlarge load additions will require the involvement of both federal and state actors, \nincluding the Commission, state public utility commissions, and other state and local \nentities. We are encouraged by efforts made at the state level to address issues related to \nlarge load additions that fall within state jurisdiction.122 \n \nAs discussed below, however, certain aspects of the process for integrating large \nloads onto the transmission system fall squarely within the Commission’s exclusive \njurisdiction. \n \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.123 \n \nThe Commission is a creature of statute and has jurisdiction over only those \nmatters that Congress has given it the authority to regulate.124 That authority includes \njurisdiction over the wholesale sale and transmission of electricity in interstate \ncommerce, including all facilities used for such sale and transmission.125 As relevant \n \n122 See generally NARUC April 14 ANOPR Comments (highlighting action taken \nby state public utility commissions related to large loads). \n123 Under the pro forma OATT, Eligible Customers include end-use customers \nseeking unbundled retail transmission service, pursuant to state law or public utility’s \nvoluntary offer of such service. Pro forma OATT, § 1.12 (Definitions – Eligible \nCustomer); see also CAISO Tariff, app. A, Eligible Customer. \n124 Atl. City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002). \n125 16 U.S.C. § 824(b)(1)."},{"page":30,"startToken":10937,"endToken":11379,"text":"Docket No. EL26-71-000 \n- 30 - \nhere, the Commission must ensure that the rates, charges, and classifications for such \ntransmission of electricity—as well as the practices directly affecting such transmission \nof electricity—are just and reasonable and not unduly discriminatory or preferential.126 \nThe Supreme Court has held that the Commission’s authority over interstate transmission \nis not limited to wholesale transmission service and that the Commission has authority \nover unbundled retail transmission service.127 As part of its transmission authority, the \nCommission has exercised jurisdiction over the terms of certain interconnections to the \ntransmission system as an element of transmission service,128 including the \ninterconnection of wholesale load to the transmission system.129 \n \nAs applied to large load additions to the transmission system, these principles \nmean that the Commission has exclusive jurisdiction over the rates, terms, and conditions \nof interstate transmission service to Eligible Customers on behalf of large loads \nconnecting to the transmission system, and the practices directly affecting the provision \nof such interstate transmission of electricity. An essential component of providing such \ntransmission service is the process by which the transmission provider and/or \ntransmission owner evaluates (1) whether it can provide the requested transmission \nservice and (2) the impact that providing such transmission service will have on the \njurisdictional transmission system, including determining whether any new or upgraded \ntransmission facilities are needed to provide transmission service while maintaining \nreliable operation of the transmission system. This transmission service study process \ndetermines what network upgrades are needed to provide transmission service to Eligible \nCustomers on behalf of large loads, the costs of which are included in transmission rates. \nAs such, this study process directly affects Commission-jurisdictional transmission \nrates.130 The Commission has exclusive authority to ensure that the process to study the \n \n126 Id. §§ 824d, 824e; see FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 278 \n(2016) (EPSA) (approving “a common-sense construction of the FPA’s language, \nlimiting FERC’s ‘affecting’ jurisdiction to rules or practices that ‘directly affect the \nwholesale rate’” (cleaned up)). \n127 New York v. FERC, 535 U.S. at 17, 19-20 (upholding the Commission’s \nexercise of jurisdiction over unbundled retail transmission service). \n128 Tenn. Power Co., 90 FERC ¶ 61,238, at 61,761 (2000) (Tennessee Power), \norder denying reh’g, 91 FERC ¶ 61,271 (2000); Standardization of Generator \nInterconnection Agreements & Procs., Order No. 2003, 104 FERC ¶ 61,103, at P 9 \n(2003); see also Laguna Irrigation Dist., 91 FERC ¶ 61,340, at 62,152 (2000). \n129 Pac. Gas & Elec. Co., 109 FERC ¶ 61,392, at P 37 (2004); Pac. Gas & Elec. \nCo., 115 FERC ¶ 61,193, at PP 36-38 (2006). \n130 Cf. Transmission Plan. & Cost Allocation by Transmission Owning &"},{"page":31,"startToken":11379,"endToken":11833,"text":"Docket No. EL26-71-000 \n- 31 - \nprovision of transmission service to Eligible Customers is just and reasonable and not \nunduly discriminatory or preferential. We therefore find that we have authority to ensure \nthat tariffs include provisions that clearly and consistently address the study process for \nthe provision of transmission service to Eligible Customers on behalf of large loads, \nincluding the unique impacts that providing transmission service to Eligible Customers \non behalf of large loads may have on the transmission system. \n \nAt the same time, we continue to recognize that the FPA expressly reserves to \nstates the authority over any other sale of electric energy, including retail sales and \nwholesale sales not in interstate commerce (such as wholesale sales within the Electric \nReliability Council of Texas region), as well as facilities used for the generation and \ndistribution of electricity.131 As such, we recognize that states will continue to regulate: \n(1) the specific terms of retail sales to large load;132 (2) which entities may make retail \nsales within their borders, including which entities are legally permitted to provide \nelectricity to retail large load customers;133 and (3) any siting decisions and construction \nassociated with the large load project.134 Nothing in this order is intended to intrude upon \nstate authority over retail service to large loads. \n \nIn sum, we today exercise our authority to ensure that the process by which \njurisdictional transmission providers and/or transmission owners will study the provision \nof jurisdictional transmission service to Eligible Customers on behalf of large loads \ninterconnecting to the transmission system, including where, as allowed by state law a \npublic utility’s voluntary offer of such service, an end-use large load seeks unbundled \n \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.”). \n131 16 U.S.C. § 824(b)(1); see Dayton Power & Light Co. v. FERC, 126 F.4th \n1107, 1129 (6th Cir. 2025). \n132 See EPSA, 577 U.S. at 279-80 (recognizing state authority over retail electricity \nsales); New York v. FERC, 535 U.S. at 28 (same). \n133 PJM Show Cause Order, 190 FERC ¶ 61,115 at PP 68-69. \n134 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th 229, 238 (D.C. \nCir. 2025) (citing 16 U.S.C. § 824(b)(1)) (recognizing state authority over generation \nresource mix, including through their siting authority); Order No. 1000, 136 FERC \n¶ 61,051 at P 107 (acknowledging state authority over siting, permitting, and construction \nof transmission facilities)."},{"page":32,"startToken":11833,"endToken":12284,"text":"Docket No. EL26-71-000 \n- 32 - \nretail transmission service, is just and reasonable and not unduly discriminatory or \npreferential. Pursuant to that authority, we find that CAISO’s Tariff and/or TO Tariffs \nappear to be unjust and unreasonable or unduly discriminatory or preferential because \nthey lack sufficiently clear and consistent provisions regarding the study process related \nto the provision of transmission service to Eligible Customers on behalf of large loads. \nWe need not comprehensively address the Commission’s jurisdiction over other aspects \nof the addition of large loads to the transmission system at this time. \n2. \nTariff Provisions \n \nIn the following section, we begin by considering CAISO’s Tariff and/or the TO \nTariffs as they relate to how CAISO and/or the Participating Transmission Owners will \nstudy the provision of transmission service to Eligible Customers on behalf of large loads \nand explain our concerns that the lack of sufficiently clear and consistent provisions \nregarding the study process for the provision of transmission service to Eligible \nCustomers on behalf of large loads is unjust and unreasonable or unduly discriminatory \nor preferential. We then consider whether CAISO’s Tariff and/or the TO Tariffs are \nunjust and unreasonable without certain elements. First, we consider whether CAISO’s \nTariff and/or the TO Tariffs lack sufficiently clear and consistent tariff provisions \nestablishing an appropriate definition of large load, as a separate category of load. \nSecond, we consider whether CAISO’s Tariff and/or the TO Tariffs lack sufficiently \nclear and consistent tariff provisions establishing an application process and requirements \nfor Eligible Customers requesting transmission service on behalf of large loads and a \nstudy process that considers the unique operational challenges of providing transmission \nservice to Eligible Customers on behalf of large loads. Third, we consider whether the \nCAISO’s Tariff lacks sufficiently clear and consistent Tariff provisions establishing \nongoing operational requirements necessary to ensure that CAISO can reliably provide \ntransmission service given the unique operational impacts on the transmission system of \nproviding transmission service to Eligible Customers on behalf of large loads. Finally, \nwe consider whether CAISO’s Tariff and/or the TO Tariffs require such ongoing \noperational requirements for Eligible Customers taking transmission service on behalf of \nlarge loads to be memorialized in service agreements. \n \nWe preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be \nunjust and unreasonable or unduly discriminatory or preferential because they do not \ncontain provisions addressing with sufficient clarity and consistency how CAISO and/or \nthe Participating Transmission Owners will study the provision of transmission service to \nEligible Customers on behalf of large loads. We recognize that CAISO and/or the \nParticipating Transmission Owners may have existing load integration processes, \nincluding studies that are performed in evaluating the provision of transmission service to"},{"page":33,"startToken":12284,"endToken":12712,"text":"Docket No. EL26-71-000 \n- 33 - \nEligible Customers on behalf of large loads.135 However, we are concerned that those \nprocesses and any required studies with regard to the provision of transmission service \nare not described in their tariffs with the degree of clarity and specificity necessary to \nensure that the transmission provider can mitigate operational risks of providing \ntransmission service to Eligible Customers on behalf of large loads, given their impact on \nthe transmission system, avoid disputes regarding how studies are conducted, deter \nspeculative or duplicative requests for transmission service by Eligible Customers on \nbehalf of large loads, and help avoid excessive and unnecessary network upgrades. \n \nMoreover, we are concerned that the existing tariffs do not contain other elements \nakin to those described below, which we preliminarily find may be necessary to ensure \nthat the rates, terms, and conditions of jurisdictional transmission service are just and \nreasonable. \n \nAt the outset, we recognize that the Participating Transmission Owners may be \nprimarily responsible for conducting the studies that (1) evaluate whether a large load \nmay be interconnected to the transmission system and served by the Eligible Customer \nand (2) determine whether network upgrades are necessary to provide transmission \nservice. We appreciate that this role may stem from how CAISO and the Participating \nTransmission Owners allocated rights and responsibilities in the governing documents \nestablishing CAISO. While we do not seek to alter that allocation of rights and \nresponsibilities, we are concerned that CAISO’s Tariff and/or the TO Tariffs may not \nclearly specify which entity will be responsible for studying the provision of transmission \nservice to Eligible Customers on behalf of large loads. \n \nWe are further concerned that CAISO’s Tariff and/or the TO Tariffs lack a 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.136 CAISO itself has \nrecognized that large loads can have a disproportionate impact on system reliability due \nto their size and unique characteristics and that the scale, pace, and characteristics of \nlarge load growth present significant operational and planning challenges.137 As a result, \n \n135 See supra P 25. \n136 See, e.g., SPP HILL Order, 194 FERC ¶ 61,031 at PP 7-8; NERC, \nCharacteristics and Risks of Emerging Large Loads (July 2025), \nhttps://www.nerc.com/globalassets/who-we-are/standing-committees/rstc/whitepaper-\ncharacteristics-and-risks-of-emerging-large-loads.pdf (NERC Characteristics and Risks \nof Large Loads). \n137 See CAISO November 21 ANOPR Comments at 1-2."},{"page":34,"startToken":12712,"endToken":13156,"text":"Docket No. EL26-71-000 \n- 34 - \nproviding transmission service to Eligible Customers on behalf of large loads may be \nmore complex and could raise greater reliability concerns for the transmission system, \nrelative to a situation where Eligible Customers seek transmission service on behalf of \ntraditional load. \n \nWithout a clear and consistent process to study the provision of transmission \nservice to Eligible Customers on behalf of large loads, CAISO and/or the Participating \nTransmission Owners may not fully capture the transmission system impacts of providing \nsuch transmission service, which could result in significant operational risks for the \ntransmission system. Furthermore, we are concerned that, without sufficiently clear and \nconsistent tariff provisions, CAISO will not have the ongoing visibility and operational \ncontrol necessary to provide reliable transmission service. \n \nWe are also concerned that the absence of sufficiently clear and consistent tariff \nprovisions for how CAISO and/or the Participating Transmission Owners will study the \nprovision of transmission service to Eligible Customers on behalf of large loads will lead \nto disputes over a variety of issues—e.g., study timelines and delays,138 how the \ntransmission service needed on behalf of the large load is studied,139 what types of \nnetwork upgrades are considered, and how required network upgrades to provide the \nrequested transmission service are determined.140 Such disputes may arise from the lack \n \n138 See, e.g., CEBA November 21 ANOPR Comments at 12-13; Eolian November \n21 ANOPR Comments at 14-16; Institute for Progress November 21 ANOPR Comments \nat 7-8; Microsoft November 21 ANOPR Comments at 9; ODEC December 5 ANOPR \nComments at 4. \n139 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. \n140 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"},{"page":35,"startToken":13156,"endToken":13585,"text":"Docket No. EL26-71-000 \n- 35 - \nof transparency in how studies are performed and how decisions will be made.141 We are \nthus concerned that the lack of clear and consistent provisions in CAISO’s Tariff and/or \nthe TO Tariffs related to the study process for the provision of transmission service to \nEligible Customers on behalf of large loads appears to be unjust and unreasonable or \nunduly discriminatory or preferential. \n \nLastly, we are concerned that CAISO’s existing Tariff and/or the TO Tariffs fail to \ndeter speculative or duplicative requests for transmission service by Eligible Customers \non behalf of large loads. Many ANOPR comments assert that clear and consistent \nprovisions establishing study timelines and costs, readiness requirements, and/or \npenalties will deter speculative or duplicative requests related to large load additions.142 \nCommenters explain that speculative requests may bog down and delay the study \nprocess, wasting time and resources for transmission providers;143 result in inaccurate \nstudy results or delays for other Eligible Customers seeking transmission service on \n \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. \n141 See, e.g., CEBA November 21 ANOPR Comments at 12; ECA December 5 \nANOPR Comments at 1-2; Eolian November 21 ANOPR Comments at 17-18; EPSA \nNovember 21 ANOPR Comments at 6; Infrastructure Masons December 5 ANOPR \nComments at 4, 6-7; Southeast PIOs November 21 ANOPR Comments at 39-40; Switch \nDecember 5 ANOPR Comments at 3; Tract November 21 ANOPR Comments at 5; \nVantage November 21 ANOPR Comments at 5-6; Verrus November 21 ANOPR \nComments at 6, 12; Vistra December 5 ANOPR Comments at 27. \n142 See, e.g., ACORE November 21 ANOPR Comments at 6; AEU November 21 \nANOPR Comments at 17-18; Amazon November 21 ANOPR Comments at 6; Crusoe \nDecember 5 ANOPR Comments at 5-6; EDF Power November 21 ANOPR Comments at \n12-13; EEI November 21 ANOPR Comments at 20; Fervo November 21 ANOPR \nComments at 3; GridCare December 5 ANOPR Comments at 5; Invenergy November 21 \nANOPR Comments at 6; Microsoft November 21 ANOPR Comments at 9; Ohio FEA \nNovember 21 ANOPR Comments at 4. \n143 See, e.g., ATC November 21 ANOPR Comments at 12; Eolian November 21 \nANOPR Comments at 17-18; GridCare December 5 ANOPR Comments at 5; Illinois AG \nNovember 21 ANOPR Comments at 9-10; Institute for Progress November 21 ANOPR \nComments at 9; Ohio FEA November 21 ANOPR Comments at 4; Vistra November 21 \nANOPR Comments at 23."},{"page":36,"startToken":13585,"endToken":13961,"text":"Docket No. EL26-71-000 \n- 36 - \nbehalf of load;144 create a substantial risk of cost shifts if the large load additions do not \nmaterialize as planned;145 and distort load forecasts.146 Clear and consistent study \nprocedures that include readiness requirements (i.e., meaningful milestones and/or \nfinancial commitments) can help ensure that Eligible Customers’ requests for \ntransmission service on behalf of large loads are more viable and more likely to \nmaterialize as planned, given that they must meet specific milestones and/or pay costs to \nproceed. \n \nMore specifically, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs \nappear to be unjust and unreasonable because they lack sufficiently clear and consistent \ntariff provisions that address certain aspects of the process to provide transmission \nservice to Eligible Customers 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 \n144 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. \n145 See, e.g., Buckeye November 21 ANOPR Comments at 1-2; Exelon November \n21 ANOPR Comments at 3; Kansas Commission November 21 ANOPR Comments at \n12; NRECA November 21 ANOPR Comments at 9; OCC November 21 ANOPR \nComments at 9; Southeast PIOs November 21 ANOPR Comments at 20; State Entities \nNovember 21 ANOPR Comments at 7-8; TAPS November 21 ANOPR Comments at 15, \n22-24; Tri-State November 21 ANOPR Comments at 6, 8; Vistra November 21 ANOPR \nComments at 23. \n146 See, e.g., CEBA November 21 ANOPR Comments at 8; EEI November 21 \nANOPR Comments at 20; ELCON November 21 ANOPR Comments at 7; Invenergy \nNovember 21 ANOPR Comments at 6; GridCare December 5 ANOPR Comments at 5; \nOCC November 21 ANOPR Comments at 9; PIOs November 21 ANOPR Comments at \n5; Southeast PIOs November 21 ANOPR Comments at 41; Talen November 21 ANOPR \nComments at 9."},{"page":37,"startToken":13961,"endToken":14417,"text":"Docket No. EL26-71-000 \n- 37 - \n(3) ongoing operational requirements for transmission customers147 serving large \nloads necessary to ensure reliable operation of the transmission system; and \n(4) pro forma provisions in transmission service agreements, or other applicable \nagreements, to memorialize these terms. \n \nFirst, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be \nunjust and unreasonable because they lack a definition of large load, as a new category of \nload. As CAISO acknowledges, integrating large loads poses specific challenges. \nCAISO states that although large loads are retail customers, they can impact reliability in \nways comparable to large wholesale generators.148 An appropriate definition, including a \nload size and interconnection voltage threshold, should be based on the characteristics of \nCAISO’s transmission system. That said, based on the record in the ANOPR \nproceeding,149 it appears that it would be reasonable to define a large load as a new \ncommercial or industrial customer, located at a single site behind one or more points of \ninterconnection, and that has a peak load of 50 MW or greater, interconnects to the \ntransmission system at a voltage level of greater than 69 kV, and is not part of a co-\nlocation arrangement. In their responses to this order, CAISO and/or the Participating \nTransmission Owners should explain whether their tariffs remain just and reasonable \nwithout such a definition or propose tariff revisions establishing their own definition of \nlarge load. \n \nSecond, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to \nbe unjust and unreasonable because they lack sufficiently clear and consistent provisions \nestablishing the application process and study procedures that will be used when CAISO \n \n147 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. \n148 CAISO November 21 ANOPR Comments at 1-2. \n149 See, e.g., Constellation November 21 ANOPR Comments at 13 (supporting a \nvoltage threshold); DTE November 21 ANOPR Comments at 3, 17-19 (recommending a \nthreshold of an amount between 50 MW to 100 MW); Eolian November 21 ANOPR \nComments at 8-9 (recommending a voltage threshold greater than or equal to an amount \nbetween 60 kV to 100 kV); Illinois AG November 21 ANOPR Comments at 7 \n(supporting a 20 MW or 50 MW threshold and consideration of other factors, such as \nvoltage level); ITC November 21 ANOPR Comments at 3 (recommending a threshold of \nbetween 50 MW to 100 MW); Nebraska Board November 21 ANOPR Comments at 4 \n(proposing a 50 MW threshold); New Mexico Commission November 21 ANOPR \nComments at 5 (proposing a 50 MW threshold)."},{"page":38,"startToken":14417,"endToken":14874,"text":"Docket No. EL26-71-000 \n- 38 - \nand/or the Participating Transmission Owners evaluate the provision of transmission \nservice to Eligible Customers on behalf of large loads. CAISO and/or the Participating \nTransmission Owners should explain whether their tariffs remain just and reasonable, for \nexample, without: (1) an application process that accepts Eligible Customers’ \napplications for transmission service on behalf of large loads on a rolling basis; (2) a \nnon-refundable application fee and sufficient readiness requirements that escalate at \ndistinct phases of the study process to deter duplicative or speculative requests for \ntransmission service (e.g., meaningful milestones and/or financial commitments); and (3) \ninformation and data requirements that Eligible Customers must submit to CAISO and/or \nthe Participating Transmission Owners regarding the characteristics of the large load on \nbehalf of which the Eligible Customer is taking transmission service, including disclosure \nto CAISO of any substantially similar pending transmission service requests on behalf of \nthe same large load customer.150 CAISO and/or the Participating Transmission Owners \nmay also elect to propose tariff revisions establishing such an application process, fee, \nand requirements. \n \nFurther, CAISO’s Tariff and/or the TO Tariffs appear to lack sufficiently clear and \nconsistent provisions establishing a study process for evaluating the provision of \ntransmission service to Eligible Customers on behalf of large loads that considers the \nunique characteristics and impacts of large loads on the transmission system. For \nexample, we are concerned that CAISO’s Tariff and/or the TO Tariffs may not clearly \nand consistently require CAISO or the Participating Transmission Owners to conduct \nstudies that evaluate the transmission system’s ability to withstand risks observed from \nanalyzed large load behavior created by the large load at the point of interconnection, or \nany other necessary supplemental studies to evaluate the impact of providing \ntransmission service to Eligible Customers on behalf of large loads.151 Additionally, we \npreliminarily find that CAISO’s Tariff and/or TO Tariffs appear to be unjust and \nunreasonable because they lack appropriate provisions recognizing within the study \nprocess for the provision of transmission service the unique operational characteristics of \nlarge loads that are willing and able to limit their energy withdrawals under certain \nconditions, which may thereby lessen or potentially avoid the need for certain network \nupgrades. While flexible large loads can reduce the demand on the transmission system, \n \n150 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). \n151 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)."},{"page":39,"startToken":14874,"endToken":15263,"text":"Docket No. EL26-71-000 \n- 39 - \nand therefore 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.152 Additionally, we note that \naccurate models using Electromagnetic Transient studies may help to ensure that \ntransmission service needed on behalf of large loads can be provided without \ncompromising reliability.153 \n \nAdditionally, we preliminarily find that CAISO’s Tariff and/or TO Tariffs appear \nto be unjust and unreasonable because they lack clear and consistent provisions requiring \nthe evaluation of alternative transmission technologies154 as potential solutions to \naccommodate an Eligible Customer’s request for transmission service on behalf of a large \nload. Alternative transmission technologies can add more capacity on existing \ntransmission lines quickly, often within one to three years.155 Unlike with traditional load \ngrowth,156 large load customers often have development timelines requiring \n \n152 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. \n153 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. \n154 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). \n155 WATT and Advancing Modern Powerlines November 21 ANOPR Comments \nat 5-6. \n156 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"},{"page":40,"startToken":15263,"endToken":15711,"text":"Docket No. EL26-71-000 \n- 40 - \ninterconnection to the transmission system faster than traditional network upgrades can \nbe built, necessitating a sufficient evaluation of alternative transmission technologies that \ncan more quickly accommodate transmission service requests from Eligible Customers \non behalf of large loads.157 The Commission has previously recognized that alternative \ntransmission technologies have the potential to mitigate or defer the need for traditional \nnetwork upgrades and often can be deployed both more quickly and at lower cost than \ntraditional network upgrades, and therefore failing to consider whether alternative \ntransmission technologies can meet transmission needs more efficiently or cost-\neffectively than traditional network upgrades has the potential to render Commission-\njurisdictional rates unjust and unreasonable.158 Further, to the extent network upgrade \ncosts to accommodate an Eligible Customer’s request for transmission service on behalf \nof a large load are rolled into a transmission owner’s transmission revenue requirement, \ntransmission customers other than the Eligible Customer may bear a portion of those \n \nunlike more traditional loads [including] size, strong desire for faster interconnection, and \npotential flexibility.”). \n157 Exec. Off. of the President, Winning the Race: America’s AI Action Plan at 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, at 4 \n(Mar. 2026), https://www.esig.energy/wp-content/uploads/2026/03/ESIG-Historical-vs-\nModern-Large-Loads-white-paper-2026.pdf (describing the timing mismatch between \nhow long it takes to build a new data center and how long it takes to plan, permit, and \nbuild transmission). \n158 Improvements to Generator Interconnection Procs. & Agreements, Order No. \n2023, 184 FERC ¶ 61,054 at P 1583, order on reh’g, 185 FERC ¶ 61,063 (2023), order \non reh’g, Order No. 2023-A, 186 FERC ¶ 61,199, errata notice, 188 FERC ¶ 61,134 \n(2024); see also Bldg. for the Future Through Elec. Reg’l Transmission Plan. & Cost \nAllocation, Order No. 1920, 187 FERC ¶ 61,068 at P 1201, order on reh’g, Order No. \n1920-A, 189 FERC ¶ 61,126 (2024), order on reh’g, Order No. 1920-B, 191 FERC \n¶ 61,026 (2025)."},{"page":41,"startToken":15711,"endToken":16182,"text":"Docket No. EL26-71-000 \n- 41 - \nnetwork upgrade costs, highlighting the need for clear and consistent provisions requiring \nthe evaluation of least-cost options like alternative transmission technologies to mitigate \nthe rate impact on all transmission customers. \n \nCAISO and/or Participating Transmission Owners should explain whether the \nTariffs remain just and reasonable without provisions that (1) require the evaluation of \nalternative transmission technologies in studies for the provision of transmission service, \nusing models that are capable of evaluating the transmission system to accurately account \nfor advanced transmission technologies, in all instances, without the need for a request \nfrom the Eligible Customer seeking transmission service on behalf of a large load; and \n(2) if traditional network upgrades are selected instead of alternative transmission \ntechnologies, inclusion in the study report to the Eligible Customer seeking transmission \nservice on behalf of a 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; or propose Tariff \nrevisions establishing such provisions. This transparency and informational requirement \nis warranted for the regulatory scheme we are establishing for transmission service \nrequests by Eligible Customers on behalf of large loads given demand from and the \nexpedited development timelines for large load customers. We underscore that we are \nnot mandating the use of alternative transmission technologies. To the extent \nstakeholders believe that specific characteristics of providing transmission service to \nEligible Customers on behalf of large loads warrant requirements beyond those \ncontemplated here, we seek further briefing. \n \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.159 To the extent CAISO or the Participating Transmission Owners already \nhave such procedures and conduct such studies, but those processes are not included in \ntheir tariffs, CAISO and the Participating Transmission Owners should explain their \n \n159 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":42,"startToken":16182,"endToken":16678,"text":"Docket No. EL26-71-000 \n- 42 - \nexisting processes and consider whether amendments are necessary to the tariffs to \nmemorialize those processes and also address the concerns expressed herein. Otherwise, \nCAISO and/or the Participating Transmission Owners should explain whether their tariffs \nremain just and reasonable without: (1) sufficiently clear and consistent provisions to \nevaluate the impact of providing the requested transmission service to Eligible Customers \non behalf of large loads, including identifying the Direct Assignment Facilities and \nNetwork Upgrades necessary to provide such service reliably; (2) provisions to \nappropriately recognize within the transmission service study process the unique \noperational characteristics of large loads; (3) a study deadline of no more than 60-90 \ncalendar days; or propose Tariff revisions establishing them. \n \nThird, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to \nbe unjust and unreasonable because they lack provisions addressing ongoing operational \nrequirements for transmission customers taking transmission service on behalf of large \nloads. We are concerned that without such requirements the rates, terms, and conditions \nof transmission service may be unjust and unreasonable. The unique nature of these large \nloads creates challenges for operation of the transmission system and necessitates greater \nvisibility and operational control when providing transmission service to transmission \ncustomers on behalf of large loads, without which the reliability of the transmission \nsystem could be at risk.160 For example, we are concerned that CAISO’s Tariff and/or \nthe TO Tariffs do not require transmission customers to provide CAISO hourly forecasts, \ntelemetry data, and other data to ensure sufficient visibility or specify requirements for \nmaintaining communication channels between CAISO and the transmission customer on \nbehalf of the large load. Additionally, we are concerned that the tariffs do not require \ntransmission owners to install, and transmission customers to pay for, equipment to \nenable CAISO to monitor large loads for impacts of, for example, fast-ramping load that \nmay impact the transmission system too quickly to be captured by conventional data \nacquisition systems (e.g., the need for phasor measurement units or similar equipment). \nWe are also concerned that the Tariff does not require the transmission customer to \nenable CAISO to remotely disconnect large loads when necessary to maintain reliability \nof the transmission system, with the costs of such equipment directly assigned to the \ntransmission customer, as well as the terms and conditions under which CAISO may \nremotely disconnect the large load (e.g., emergency conditions, so that transmission \nequipment is not harmed). Further, we are concerned that the tariffs do not specify ramp \nrate 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 transmission customer’s withdrawals \n \n160 E.g., ATC November 21 ANOPR Comments at 14; CAISO November 21 \nANOPR Comments at 10 (citing NERC Characteristics and Risks of Large Loads); Herb \nSchrayshuen November 21 ANOPR Comments at 2-5."},{"page":43,"startToken":16678,"endToken":17087,"text":"Docket No. EL26-71-000 \n- 43 - \nfrom the transmission system as appropriate.161 CAISO and/or the Participating \nTransmission Owners should explain whether the tariffs remain just and reasonable \nwithout these or other ongoing operational requirements as part of the rates, terms, and \nconditions of transmission service or propose tariff revisions establishing necessary \nongoing operational requirements. \n \nFourth, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to \nbe unjust and unreasonable because they lack pro forma provisions in a transmission \nservice agreement, or other applicable agreement, between CAISO and/or the \nParticipating Transmission Owner and the transmission customer taking transmission \nservice on behalf of a large load to memorialize the above terms (e.g., equipment \nrequirements, data requirements, remote disconnect capability). We are concerned that, \nwithout such pro forma provisions in a transmission service agreement, or other \napplicable agreement, between CAISO and/or the Participating Transmission Owner and \nthe transmission customer, CAISO may be unable to enforce ongoing operational \nrequirements for transmission customers taking transmission service on behalf of large \nloads. CAISO and/or the Participating Transmission Owners should explain whether \ntheir Tariffs remain just and reasonable without such pro forma provisions in a \ntransmission service agreement, or other applicable agreement, or propose revisions to \ninclude pro forma provisions memorializing the ongoing operational requirements in a \ntransmission service agreement between CAISO and/or the Participating Transmission \nOwner and the transmission customer. \nB. \nCost Shifting Risk Among Transmission Customers \n \nWe next preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be \nunjust and unreasonable because they lack adequate mechanisms to mitigate the risk of \ncost shifting among transmission customers, which may result in unjust and unreasonable \nrates for transmission service. In particular, we are concerned about the apparent lack of \n(1) transparency regarding the assignment of network upgrades, and their associated \ncosts, that are needed to provide transmission service to Eligible Customers on behalf of \nlarge loads; and (2) a pro forma cost recovery agreement between CAISO, the relevant \ntransmission owner, and the Eligible Customer taking transmission service on behalf of \nlarge loads that help ensure that Eligible Customers bear the risk and are ultimately \nresponsible for costs incurred to provide transmission service, including the cost of \nnetwork upgrades. \n \n161 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 101, \n105."},{"page":44,"startToken":17087,"endToken":17560,"text":"Docket No. EL26-71-000 \n- 44 - \n \nWe direct CAISO and the Participating Transmission Owners, to the extent the \nmatters addressed herein implicate aspects of their tariffs, to explain whether the tariffs \nremain just and reasonable without (1) robust, accurate, and systematic provision of data \non CAISO’s website in a single location, and in an easily accessible format that is \nsearchable and allows users to filter the data, regarding the cost for network upgrades \nneeded to provide transmission service to Eligible Customers on behalf of large loads; \nand (2) a pro forma cost recovery agreement between CAISO, the relevant transmission \nowner, and the Eligible Customer taking transmission service on behalf of a large load, or \nto propose tariff revisions to provide additional transparency and establish such a pro \nforma cost recovery agreement. We encourage state regulators responsible for setting \nretail rates to provide input to CAISO regarding their transparency needs. \n1. \nJurisdiction \n \nThe Commission has a duty to address the risk of cost shifting among transmission \ncustomers that may result in unjust and unreasonable transmission rates. As explained \nabove, the Commission is obligated to ensure that the rates charged for jurisdictional \ntransmission service—as well as any practice directly affecting such rates—are just and \nreasonable and not unduly discriminatory or preferential. With respect to the addition of \nlarge loads to the transmission system, the Commission has exclusive authority to ensure \nthat transmission rates are just and reasonable. The costs of those upgrades to the \ntransmission system (i.e., network upgrades) necessary to provide transmission service to \nEligible Customers on behalf of large loads are inputs to jurisdictional transmission rates, \nand thus directly affect the Commission-jurisdictional rates paid by transmission \ncustomers. To fulfill its responsibility to ensure that transmission rates are just and \nreasonable, the Commission must act to address the risk of cost shifting among \ntransmission customers due to (1) the process transmission providers and/or transmission \nowners use to evaluate the facilities needed, and the associated costs, for the provision of \ntransmission service to Eligible Customers on behalf of large loads and (2) speculative \ntransmission service requests by Eligible Customers on behalf of large loads that could \nresult in unjust and unreasonable transmission rates. \n \nIn response to the ANOPR, many commenters raise concerns about the impact that \nlarge load additions can have on retail ratepayers, particularly the concern that other retail \nratepayers may be forced to subsidize network upgrades needed to add large loads to the \ntransmission system.162 While we appreciate and are similarly concerned about this \nissue, the Commission is limited to addressing jurisdictional transmission rates and as \n \n162 See, e.g., Southern California Edison December 5 ANOPR Comments at 3; see \nalso CPUC November 21 ANOPR Comments at 16 (noting that it supports ratepayer \nprotections and efforts to mitigate risk of cost shifting); State Entities November 21 \nANOPR Comments at 7-8."},{"page":45,"startToken":17560,"endToken":17988,"text":"Docket No. EL26-71-000 \n- 45 - \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.163 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.164 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,165 as well as voluntary efforts by transmission owners to protect \nretail ratepayers through cost recovery agreements with large loads.166 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.167 We expect that the additional cost transparency measures proposed \nin the following section will give state public utility commissions and other state \nregulators the information necessary to allow them to understand which transmission \ncosts are caused by which transmission customers, so that they can sub-allocate these \ncosts to the appropriate retail customers. Indeed, the Commission’s objective in this \nproceeding is to respect the cooperative federalism approach established under the FPA. \nSpecifically, one of the benefits of providing transparency on the costs of network \nupgrades necessary to provide transmission service to Eligible Customers on behalf of \nlarge loads is so that state regulators can use that information to protect residential and \nsmall commercial customers by incorporating those costs into the retail rates as they see \nfit given their authority to set rates for different classes of retail customers. \n \nWe encourage state public utility commissions, state regulators and state consumer \nadvocates to submit comments explaining whether this information is sufficient and \ngranular enough or to submit comments explaining precisely which additional \ninformation on transmission cost allocation may be needed to inform proper state-\njurisdictional cost allocation. \n \n163 PJM Show Cause Order, 190 FERC ¶ 61,115 at P 167. \n164 Id. P 68. \n165 See, e.g., CPUC November 21 ANOPR Comments at 2; PG&E November 21 \nANOPR Comments at 1-2. \n166 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). \n167 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":46,"startToken":17988,"endToken":18403,"text":"Docket No. EL26-71-000 \n- 46 - \n2. \nAdditional Cost Transparency \n \nWe preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be \nunjust and unreasonable or unduly discriminatory or preferential because they do not \ncontain provisions requiring the provision of data on CAISO’s website in a single \nlocation, and in an easily accessible format that is searchable and allows users to filter the \ndata, on transmission service provided to Eligible Customers on behalf of large loads, for \nnetwork upgrades evaluated in the local transmission planning process that are needed to \naccommodate transmission service to Eligible Customers on behalf of those large loads, \nand the costs for those network upgrades. We preliminarily find that cost transparency \nmeasures are needed to provide stakeholders with sufficient information and visibility \nregarding the network upgrades, and their associated costs, needed to accommodate \ntransmission service to Eligible Customers on behalf of large loads. \n \nIn its annual Transmission Plan, CAISO publishes the status, costs, and scope of \nprojects from prior Transmission Plans that are not yet completed and projects that are \nnew to the Transmission Plan.168 The Transmission Plan for 2025-2026 includes a \nsection on projects that CAISO reviewed and concurred with for large load \ninterconnections that identifies the project, estimated in-service date, and cost.169 Section \n24 of CAISO’s Tariff describes the TPP and inputs required to develop the Transmission \nPlan,170 such as the Unified Planning Assumptions and Study Plan. However, the Tariff \ndoes not specify what information the published Transmission Plan should contain, \nleaving the contents of the Transmission Plan to be prescribed in a Business Practice \nManual. The Transmission Planning Process Business Practice Manual requires the \nTransmission Plan to contain a description of: (1) solutions with capital costs of $50 \nmillion or more for which CAISO has completed all necessary studies; (2) solutions with \ncapital costs of less than $50 million that have been approved by CAISO management; \nand (3) solutions for which additional studies are required.171 \n \n168 See CAISO, Business Practice Manual for the Transmission Planning Process, \n§ 4.9.2 (Transmission Plan Contents). \n169 See CAISO, 2025-2026 Transmission Plan 91-94 (May 12, 2026), \nhttps://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/2025-2026-\nTransmission-planning-process. \n170 CAISO defines the Transmission Plan as: “The report prepared by the CAISO \non annual basis pursuant to Section 24, which documents the outcome of the \nTransmission Planning Process as defined in the Study Plan.” CAISO Tariff, app. A, \nTransmission Plan (0.0.0). \n171 See CAISO, Business Practice Manual for the Transmission Planning Process,"},{"page":47,"startToken":18403,"endToken":18891,"text":"Docket No. EL26-71-000 \n- 47 - \n \nHowever, CAISO’s Tariff and/or the TO Tariffs do not appear to require that \ninformation identifying the network upgrades needed to accommodate transmission \nservice to Eligible Customers on behalf of large loads and the costs of those network \nupgrades determined through the local transmission planning processes be readily \navailable on CAISO’s website in a single location, and in an easily accessible format that \nis searchable and allows users to filter the data. We acknowledge and are encouraged by \nthe fact that CAISO has published in its most recent Transmission Plan some of the \ntransmission facilities driven by large load additions, but we preliminarily find that it is \nnecessary that CAISO’s Tariff and/or the TO Tariffs require such information to be \ntransparently and consistently reported in the future. The speed and scale with which \nEligible Customers are seeking transmission service on behalf of large loads makes it \ndifficult for interested parties, including transmission customers and state regulators, to \naccurately assess which transmission costs are the result of accommodating transmission \nservice for Eligible Customers to serve large loads. We are concerned that the potentially \nspeculative nature of accommodating transmission service for Eligible Customers on \nbehalf of large loads,172 the speed and scale with which large loads are seeking to be \nadded to the transmission system, the projected need for significant network upgrades to \nprovide transmission service to Eligible Customers on behalf of large loads, and the lack \nof centralized information on the associated transmission costs in CAISO hamper the \nability of the Commission and stakeholders (including transmission customers and state \nregulators173) to understand and accurately assess the relationship between the addition of \nlarge loads to the transmission system and wholesale transmission costs. \n \nWe are concerned that without sufficient transparency regarding the network \nupgrades, and their associated costs, needed to provide transmission service to Eligible \nCustomers on behalf of large loads, stakeholders may lack information and visibility \n \n§ 4.9.2.1 (Transmission Plan Contents). \n172 See supra P 55. \n173 See Transcript, NARUC Collaborative, Docket No. AD24-7-000, at 16-17 \n(Feb. 11, 2026) (Chair Bagot, Virginia) (asserting that additional transparency at the RTO \nlevel would help the states get the information they need to “identify . . . that bucket of \ncosts” related to large load-driven transmission costs), 19 (Commissioner Chattopadhyay, \nNew Hampshire) (noting the need for “all parties to be able to see things transparently” \nwith respect to wholesale transmission costs), 35-37 (Chair Martz, Iowa) (raising concern \nthat currently RTOs/ISOs do not have to clearly explain when a “bucket of costs is \nspecifically for this large load” and noting that “if we, at the state level, can’t see the \ndriver [of transmission costs], we can’t assign the cost to the causer[,] [a]nd so we need \nthat clarity”), 69-70 (Chair Myers, Arizona) (“[B]eing able to allocate the large load costs \nto the correct bucket when it gets to the states is kind of a top priority.”)."},{"page":48,"startToken":18891,"endToken":19339,"text":"Docket No. EL26-71-000 \n- 48 - \nregarding the costs driven by large load additions. We preliminarily find that, for \nnetwork upgrades evaluated in the local transmission planning process174 that are needed \nto accommodate transmission service for Eligible Customers on behalf of large loads are \nevaluated, CAISO must provide clear, timely, and detailed information regarding the \nextent to which accommodating transmission service for Eligible Customers on behalf of \nlarge loads necessitates network upgrades, as well as the costs of those network upgrades. \n \nWe note that centralized information regarding network upgrades needed for \naccommodating transmission service for Eligible Customers on behalf of large loads \nwould also help inform stakeholders at the state and local level to address affordability \nand other challenges posed by the integration of large loads. Indeed, commenters state \nthat the opaque nature of accommodating transmission service for Eligible Customers on \nbehalf of large loads, and the associated network upgrades required to provide that \ntransmission service, prevent wholesale and retail customers, states, and other \nstakeholders from understanding such costs.175 \n \n174 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. \n175 See OCC November 21 ANOPR Comments at 3 (“Consumers, state advocates \nand state regulatory commissions have a right to know which entities are seeking large-\nload interconnections, the nature of the requested service, and how related costs could \nflow through to transmission and distribution rates.”); U.S. House of Representatives \nCommittee on Energy and Commerce Ranking Members November 21 ANOPR \nComments at 2 (urging the Commission to “require sufficient transparency from grid \noperators so it can determine which specific large load facilities are responsible for grid \nupgrade needs”); see also CPUC November 21 ANOPR Reply Comments at 16-17 \n(asserting that the public posting of large load cost responsibility determinations would \nimprove transparency, to the benefit of businesses and ratepayers)."},{"page":49,"startToken":19339,"endToken":19819,"text":"Docket No. EL26-71-000 \n- 49 - \n \nAccordingly, we preliminarily find that CAISO’s Tariff and/or the TO Tariffs \nappear to be unjust and unreasonable because they do not require the provision of data on \nCAISO’s website in a single location, and in an easily accessible format that is searchable \nand allows users to filter the data that identifies the network upgrades that are needed to \naccommodate transmission service for Eligible Customers on behalf of large loads, and \nthe costs of those network upgrades. CAISO and/or the Participating Transmission \nOwners should explain whether their tariffs remain just and reasonable without \nprovisions that would require CAISO and the Participating Transmission Owners to \npublicly post and regularly update data that details: (1) the aggregate amounts of \nproposed large load additions in CAISO’s footprint or the Participating Transmission \nOwner’s service territory, including the aggregate amounts in each transmission pricing \nzone; and (2) the planned network upgrades needed to accommodate transmission service \nfor Eligible Customers on behalf of large loads, identified by type of equipment and \nnetwork upgrade (e.g., new substation, reconductoring, a new high-voltage transmission \nline) for each transmission service request; and (3) cost estimates for those network \nupgrades, or propose such tariff revisions. CAISO and the Participating 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 CAISO’s website. To the extent there are concerns about \ndata confidentiality, CAISO and the Participating Transmission Owners should consider \nwhether there are ways to mitigate those concerns while still providing the necessary \ntransparency. \n3. \nCost Recovery Agreements \n \nWe next preliminarily find that CAISO’s Tariff and/or the TO Tariffs appear to be \nunjust and unreasonable because they lack adequate mechanisms to mitigate the risk of \ncost shifting among transmission customers, which may result in unjust and unreasonable \nrates for transmission service. In particular, we are concerned about the apparent lack of \na pro forma cost recovery agreement between CAISO, the relevant transmission owner, \nand the Eligible Customer taking transmission service on behalf of large loads that help \nensure that Eligible Customers bear the risk and are ultimately responsible for costs \nincurred to provide transmission service, including the cost of network upgrades. \n \nSeveral commenters discuss the risk of cost shifting among transmission \ncustomers that could result from transmission service requests by Eligible Customers on \nbehalf of large loads.176 Commenters also argue that retail-level large load tariffs do not \n \n176 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"},{"page":50,"startToken":19819,"endToken":20257,"text":"Docket No. EL26-71-000 \n- 50 - \nprotect wholesale transmission customers from cost shifting.177 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.178 The Kansas Commission states that while its Large Load Power \nServices rate plan that requires large loads to make minimum payments toward \ntransmission costs protects retail ratepayers from large-load driven transmission costs, it \ncannot protect against cost shifting associated with regional transmission buildout where \n“the large loads that formed the basis for the [regional] transmission plans do not \nmaterialize, leaving only existing customers to pay for generational expansions of the \ntransmission grid.”179 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.180 \n \nWe are likewise concerned that there may be speculative transmission service \nrequests by Eligible Customers on behalf of large loads that could result in cost shifting \namong transmission customers, which may lead to unjust and unreasonable increases in \njurisdictional transmission rates. When a transmission owner constructs network \nupgrades to accommodate the provision of transmission service to an Eligible Customer \non behalf of a large load, those transmission costs will be included in the transmission \nowner’s transmission revenue requirement. If, however, the Eligible Customer takes less \ntransmission service than anticipated because the large load operates at a lower demand \nthan anticipated or fails to materialize at all, other transmission customers may see an \nincrease in transmission rates. In such a situation, those other transmission customers \n \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. \n177 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. \n178 Buckeye November 21 ANOPR Comments at 14-15; see TAPS November 21 \nANOPR Comments at 26-27 & nn.50-51. \n179 Kansas Commission November 21 ANOPR Comments at 11-12. \n180 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":51,"startToken":20257,"endToken":20728,"text":"Docket No. EL26-71-000 \n- 51 - \nmay have to pay for potentially unnecessary network upgrades that they neither caused \nthe need for nor benefit commensurately from. In other words, this introduces the risk \nthat costs may be unfairly shifted to other transmission customers, which may result in \nthose costs then being passed through to residential customers, among others. \n \nCAISO’s Tariff and/or the TO Tariffs do not require cost recovery agreements \nbetween CAISO, the relevant transmission owner and the Eligible Customer taking \ntransmission service on behalf of a large load. Such agreements would help ensure that \nthe Eligible Customer makes a minimum contribution to the transmission owner’s \ntransmission revenue requirement commensurate with the costs incurred to provide the \nrequested transmission service, including the costs of any needed network upgrades. \nAbsent such cost recovery agreements, we are concerned that there is no mechanism to \nhelp ensure that Eligible Customers taking transmission service on behalf of large loads \n(as opposed to other transmission customers) bear the risk of, and are ultimately \nresponsible for, the costs incurred to provide them with the requested transmission \nservice, including the costs of any needed network upgrades. \n \nAccordingly, we preliminarily find that, in order to prevent unjust and \nunreasonable cost shifting among transmission customers, it appears necessary for \nCAISO, the relevant transmission owner, and the Eligible Customer taking transmission \nservice on behalf of a large load to enter into a cost recovery agreement that requires the \nEligible Customer to make a minimum contribution toward the transmission owner’s \ntransmission revenue requirement if the Eligible Customer ultimately takes less \ntransmission service than anticipated because the large load does not materialize as \nplanned or is not developed at all. We preliminarily find that such cost recovery \nagreements are necessary to help ensure that the Eligible Customer is responsible for \ntimely paying the costs of large load-driven transmission (i.e., the costs incurred to \nprovide them with the requested transmission service, including the costs of any needed \nnetwork upgrades) rather than having those costs paid by other transmission customers \nthat neither caused the need for nor benefit commensurately from those network \nupgrades.181 Our preliminary finding is not intended to alter or call into question existing \nregional cost allocation methods for network upgrades, but instead is focused on helping \nto prevent cost shifting among transmission customers. \n \nWe note that several transmission owners and large load customers have filed cost \nrecovery agreements (Transmission Security Agreements or Construction Service \nAgreements) with the Commission that guarantee minimum contributions from a large \nload customer (rather than from the Eligible Customer taking transmission service on \nbehalf of the large load customer) to the transmission owner’s transmission revenue \n \n181 See, e.g., Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 \n(D.C. Cir. 2004); Ill. Com. Comm’n v. FERC, 576 F.3d 470, 476 (7th Cir. 2009)."},{"page":52,"startToken":20728,"endToken":21201,"text":"Docket No. EL26-71-000 \n- 52 - \nrequirement.182 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.183 To reduce duplicative credit requirements and \ntransaction costs, we direct further briefing on whether it would be appropriate for such \nan agreement to substitute for the requirement on the Eligible Customer to enter into a \ncost recovery agreement with the transmission owner, if the agreement with the large \nload customer provided comparable or greater protection against cost shifting among \ntransmission customers than an agreement between the transmission owner and the \nEligible Customer would. \n \nIn addition to our preliminary finding that CAISO’s Tariff and/or the TO Tariffs \nare unjust and unreasonable because they lack a pro forma cost recovery agreement of \nthis type, we also preliminarily find that the minimum contribution required pursuant to \nsuch an agreement should be based on the level of jurisdictional transmission service (in \nMW) requested by the Eligible Customer on behalf of the large load. That figure is in \nturn tied to how CAISO and/or the Participating Transmission Owners will study the \nrequested transmission service and determine any necessary network upgrades that must \nbe developed to provide the requested transmission service. We note, however, that there \nmay be other just and reasonable methods for determining this minimum contribution, \nincluding methods that account for potential timing differences between when costs are \nincurred to develop needed Network Upgrades and the pace at which the large load ramps \ntoward energizing at its full level of requested service. We further preliminarily find that \nthe cost recovery agreement should include a credit support (or other financial security) \nrequirement sufficient to secure the obligations of the Eligible Customer taking \ntransmission service on behalf of a large load to pay the amounts owed pursuant to the \ncost recovery agreement. We find that a cost recovery agreement with a specified \nminimum financial contribution and financial security sufficient to secure such \ncontribution is necessary to mitigate cost shifting if the Eligible Customer ultimately \ntakes less transmission service than anticipated because the large load does not \n \n182 See supra note 166. \n183 We emphasize that this finding is in no way intended to preempt or interfere \nwith the ability of states to implement ratepayer protection measures designed to mitigate \ncost shifting among retail customers, such as through state-jurisdictional large load \ntariffs."},{"page":53,"startToken":21201,"endToken":21631,"text":"Docket No. EL26-71-000 \n- 53 - \nmaterialize as planned or is not developed at all. We preliminarily find that an Eligible \nCustomer may include a credit support or other financial security posted by a large load \nas part of a retail agreement to avoid creating duplicative credit support requirements. \nCAISO and/or the Participating Transmission Owners should explain why such a pro \nforma cost recovery agreement is not necessary to ensure just and reasonable rates or \npropose 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.184 \n \nAlthough the Commission’s concerns surrounding cost shifting described above \nmay not present the same in CAISO as in other RTOs/ISOs, we nevertheless remain \nconcerned that cost shifting may occur. We acknowledge that the Participating \nTransmission Owners have wholesale load interconnection processes by which Eligible \nCustomers may request interconnection of their wholesale loads. We note that those \nprocesses and the related studies may result in network upgrades or transmission \nexpansion projects for which the terms and conditions are memorialized in an \ninterconnection agreement and the costs directly assigned to the Eligible Customer. \nNevertheless, we remain concerned that cost shifting may occur through the recovery of \nthe Participating Transmission Owners’ transmission revenue requirement through the \nAccess Charge due to speculative requests to accommodate transmission service to serve \nlarge loads, i.e., where large loads do not materialize or where the MW quantity of such \nlarge loads is lower than proposed, or because of the study process used to evaluate the \nfacilities needed, and the associated costs, to accommodate the provision of transmission \nservice to Eligible Customers on behalf of large loads. We are concerned because, as \nexplained above, the wholesale load interconnection process in the TO Tariffs only \napplies to a subset of Eligible Customers.185 We understand that transmission projects \nresulting from local transmission planning and regional transmission planning processes \nmay be built to accommodate load additions that are not interconnected pursuant to the \nTO Tariff. While the interconnection of such load may be subject to a process governed \nby the relevant local regulatory authority, the costs of network upgrades built to \naccommodate that load growth that is identified through CAISO’s Transmission Planning \nProcess are included in the Participating Transmission Owners’ transmission revenue \nrequirements and recovered through the Access Charge. Further, the Participating \nTransmission Owners should demonstrate whether, and if so, how, existing requirements \nregarding interconnection agreements for wholesale load interconnections protect against \ncost shifting. \n \n184 See infra P 125. \n185 See supra P 25."},{"page":54,"startToken":21631,"endToken":22032,"text":"Docket No. EL26-71-000 \n- 54 - \n \nLastly, we expect that any payments made by an Eligible Customer to a \ntransmission owner pursuant to such a cost recovery agreement (or by a large load to a \ntransmission owner pursuant to other voluntary agreement) will be appropriately credited \ntoward transmission owners’ transmission revenue requirements consistent with the \nCommission’s cost-of-service regulations.186 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 \n \nThe Commission recently addressed in the PJM region the need for sufficiently \nclear and consistent tariff provisions addressing the rates, terms, and conditions that apply \nto co-location arrangements and for transmission services that reflect an Eligible \nCustomer taking transmission service on behalf of Eligible Load187 that is willing and \nable to limit its energy withdrawals from the transmission system under certain \nconditions.188 As discussed below, CAISO’s Tariff appears to be unjust and \nunreasonable because it lacks such provisions. \n \nWe direct CAISO and the Participating Transmission Owners, to the extent the \nmatters addressed herein implicate aspects of their TO Tariffs, to explain whether the \nTariff remains just and reasonable without provisions addressing the rates, terms and \nconditions that apply to interconnection customers serving co-located load and for \nEligible Customers taking transmission service on behalf of Eligible Load, or propose \nTariff revisions establishing the rates, terms, and conditions that apply to co-location \narrangements.189 We recognize that CAISO has begun a stakeholder policy initiative \nwhich may consider reforms related to co-location arrangements, and we encourage \n \n186 See 18 C.F.R. pt. 101 (2025). \n187 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 90. \n188 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 2; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at PP 91, 102. \n189 While this section is directed to both CAISO and the Participating \nTransmission Owners, we believe it will mostly implicate the CAISO Tariff, as it appears \nthat only the CAISO Tariff involves matters related to co-location arrangements because \nthe CAISO Tariff governs the generator interconnection process and because CAISO is \nthe transmission provider."},{"page":55,"startToken":22032,"endToken":22404,"text":"Docket No. EL26-71-000 \n- 55 - \nCAISO 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 \n \nThe PJM Co-Location Order adopted the following definition of co-located load: \na “configuration [that] refers to end-use customer load that is physically connected to the \nfacilities of an existing or planned Customer Facility on the Interconnection Customer’s \nside of the Point of Interconnection to the PJM Transmission System.”190 The PJM \nCo-Location Order used the term co-location arrangement when referring to both the co-\nlocated load and the associated generator.191 \n \nFor purposes of this order, it appears that it would be reasonable to define \nco-located 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. \n \nThe CAISO Tariff does not define “Behind the Meter Generation.” For purposes \nof this order, it appears reasonable based upon the record to refer to Behind the Meter \nGeneration (BTMG) similarly to how that term is used in the PJM Co-Location Order, as \na generating facility that delivers energy to load without using the transmission system or \nany distribution facilities.192 \n \nFor purposes of this order, we will use the term Eligible Load to refer to co-\nlocated load and/or load with BTMG.193 \n2. \nJurisdiction \n \nAs explained in the PJM Co-Location Order, the Commission has exclusive \njurisdiction to oversee the interconnection of generating facilities to the interstate \ntransmission system, including where generators serve co-located load.194 The \n \n190 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 164 (alterations in original). \n191 Id. P 3. \n192 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 7 n.19 (citing PJM, \nIntra-PJM Tariffs, OATT, § I.1 (Definitions - A-B) (21.0.0)). \n193 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 91. \n194 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171 (citing 16 U.S.C."},{"page":56,"startToken":22404,"endToken":22777,"text":"Docket No. EL26-71-000 \n- 56 - \nCommission retains exclusive authority to regulate the procedures and agreements that \napply to the interconnection of a generator that will make wholesale sales, both where the \ngenerator interconnects directly to the interstate transmission system and where a \ngenerator interconnects to dual-use distribution facilities.195 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.196 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.197 \n \nAdditionally, we reiterate that certain other aspects of co-location arrangements \nfall squarely within the jurisdiction of the states. As we explained in the PJM Co-\nLocation Order, states retain exclusive authority over the specific terms of retail sales and \nretail rate design, including retail cost allocation to the co-located load; which entities are \nlegally permitted to provide electricity to retail customers in co-location arrangements; \nand which generating facilities are sited and allowed to serve co-located load.198 \n3. \nTariff Provisions \n \nWe preliminarily find that CAISO’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 CAISO’s Tariff appears to be unjust and unreasonable or unduly discriminatory or \npreferential because it does not contain provisions addressing with sufficient clarity and \nconsistency transmission services that reflect that an Eligible Customer taking \ntransmission service on behalf of Eligible Load is willing and able to limit its energy \nwithdrawals from the transmission system under certain conditions. \n \nThe absence of such provisions may leave entities unable to determine what steps \nthey can or must take to effectuate co-location arrangements of various configurations. \nOne step includes determining how interconnection customers serving co-located load \n \n§§ 824d, 824e; EPSA, 577 U.S. at 278). \n195 Id. P 172 (citing Nat’l Ass’n of Regul. Util. Comm’rs v. FERC, 475 F.3d 1277, \n1282 (D.C. Cir. 2007)). \n196 Id. P 173. \n197 Id. P 174. \n198 Id. PP 167-169."},{"page":57,"startToken":22777,"endToken":23213,"text":"Docket No. EL26-71-000 \n- 57 - \nmay use generator interconnection processes in CAISO’s Tariff to facilitate their \nco-location arrangements. A further step includes requiring interconnection customers \nserving co-located load to specify the Eligible Customer taking transmission service on \nbehalf of the co-located load under the Tariff for purposes of assessing charges, including \nthe appropriate charges for wholesale services that should apply to such Eligible \nCustomers. Without such a common and consistent understanding of entities’ \nresponsibilities relevant to co-location arrangements, many of which may significantly \naffect rates and are realistically susceptible of specification,199 we are concerned that \nthese arrangements may be developed in a manner that is itself unjust and unreasonable \nor that may result in unjust and unreasonable rates for other customers. \n \nMoreover, as discussed further below, we are especially concerned that the \nabsence of Tariff provisions addressing transmission and ancillary service rates for \nEligible Customers taking transmission service on behalf of Eligible Load creates the \npotential that Eligible Customers, on behalf of Eligible Load, may not be required to pay \nfor wholesale transmission services that they receive, as required by the cost causation \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,”200 and that costs must be allocated in a manner that is at least roughly \ncommensurate with the benefits that entity receives.201 \n \nWe preliminarily find that CAISO’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 CAISO 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 \n \n199 Hecate Energy Greene Cnty. 3 LLC v. FERC, 72 F.4th 1307, 1312 (D.C. Cir. \n2023). \n200 Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368. \n201 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d at 476."},{"page":58,"startToken":23213,"endToken":23645,"text":"Docket No. EL26-71-000 \n- 58 - \nservice.202 As such, interconnection customers seeking to use their generating facilities \nto serve co-located load have no means of knowing the appropriate mechanism for setting \nforth the terms and conditions of co-location arrangements. We are concerned that the \ndetails of such a process—including the existing rules and studies applicable to such \ngenerator interconnection arrangements—are not sufficiently detailed in the Tariff to \nensure clarity for how interconnection customers may seek to serve co-located load. \nMoreover, without an Eligible Customer designated to take transmission service on \nbehalf of a co-located load, there is no mechanism for CAISO to address situations in \nwhich a co-located load withdraws energy from the transmission system. \n \nTherefore, we preliminarily find that CAISO’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. CAISO should explain whether the Tariff remains \njust and reasonable without such provisions, or propose Tariff revisions. \n \nWe have similar concerns regarding CAISO’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.203 \nSpecifically, the Commission has found that, regardless of whether a co-located load \nwithdraws energy from the transmission system, co-located load relies on and benefits \nfrom regulation service and black start service, and concluded that Eligible Customers \ntaking one of the new transmission services (discussed below) on behalf of co-located \nload must pay for these ancillary services on a gross demand basis.204 In the PJM Co-\nLocation Rehearing Order, the Commission applied these findings to Eligible Customers \ntaking transmission service on behalf of load with BTMG.205 However, CAISO’s Tariff \ndoes not appear to include a mechanism by which an Eligible Customer, on behalf of \nEligible Load, would be charged for ancillary services commensurate with its usage of \nsuch services, particularly if such customer did not withdraw energy from the \ntransmission system. \n \n202 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. \n203 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 183. \n204 Id. PP 184-185. \n205 See PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 400."},{"page":59,"startToken":23645,"endToken":24118,"text":"Docket No. EL26-71-000 \n- 59 - \n \nTherefore, we preliminarily find that CAISO’s Tariff appears to be unjust and \nunreasonable because it does not address whether and how Eligible Customers taking one \nof the new transmission services on behalf of Eligible Loads will be charged for their use \nof regulation and black start services, which introduces the risk that Eligible Load may \nbenefit from regulation and black start services without contributing to cost recovery for \nsuch services. As noted in the PJM Co-Location Order, this introduces the risk that costs \nmay be allocated entirely to other transmission customers and passed through to \nresidential customers, among others.206 CAISO should explain whether the Tariff \nremains just and reasonable without requiring Eligible Customers taking one of the new \ntransmission services on behalf of Eligible Loads to pay for regulation and black start \nservices on a gross demand basis, or propose Tariff revisions that require them to do so. \n 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.207 On rehearing, the Commission found that it is just and \nreasonable for these services to be available to Eligible Customers taking transmission \nservice on behalf of loads with BTMG.208 We are concerned that CAISO’s Tariff lacks \ntransmission services that would reflect the ability of Eligible Customers on behalf of \nEligible Loads to take transmission services that align with their use of the transmission \nsystem, which may result in inefficient and costly transmission buildout and costs paid by \ntransmission customers.209 \n Therefore, we also preliminarily find that CAISO’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. CAISO should \n \n206 See PJM Co-Location Order, 193 FERC ¶ 61,217 at P 159. \n207 Id. P 199. \n208 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at PP 101-103. \n209 See, e.g., PSEG November 21 ANOPR Comments at 20 (“The Commission’s \nlong-standing policy is to encourage reduced use of the transmission system, which \nwould in turn reduce upgrades to the transmission system, to the benefit of all \ntransmission customers. For instance, if a co-located load’s use of the transmission \nsystem is limited (or to a lesser degree) than other traditional in front of the meter loads, \nit should be responsible for costs based on its limited use.”)."},{"page":60,"startToken":24118,"endToken":24574,"text":"Docket No. EL26-71-000 \n- 60 - \nexplain whether 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 Eligible Load, or propose appropriate Tariff revisions. Specifically, CAISO should \nexplain whether the Tariff remains just and reasonable without (1) an interim non-firm \nnetwork transmission service while network upgrades are being constructed (i.e., interim \nNITS) and (2) permanent firm and non-firm contract demand transmission services \n(transmission service up to a specified MW quantity, i.e., the contract level, on a firm or \nnon-firm basis). In the alternative, CAISO may explain whether, given that CAISO does \nnot offer the transmission services required by Order No. 888,210 CAISO’s existing \ntransmission service framework addresses the concerns described herein, or explain what \nspecific changes to its existing transmission service framework would effectively provide \nthe same range of transmission service options for flexible large loads as in the PJM Co-\nLocation Order. We note that the Commission has found it just and reasonable that, in \norder for an Eligible Customer to take interim NITS, firm contract demand transmission \nservice, and non-firm contract demand transmission service, an Eligible Customer must \nhave necessary control technologies and/or protection systems, which may include a \nspecial protection scheme, to limit its energy withdrawals to its approved level.211 \n Finally, we preliminary find that CAISO’s Tariff is unjust and unreasonable \nbecause it allows load with BTMG to net its BTMG against its load for purposes of \ncalculating Regional Access Charges.212 In the PJM Co-Location Order, the Commission \nfound that PJM’s BTMG rules, which allowed load serving entities that provide service \nto loads with qualifying BTMG to reduce their costs by netting output from BTMG in the \ncalculation of their peak demand for the purpose of determining NITS charges, were \nunjust and unreasonable.213 The Commission concluded that PJM’s BTMG rules were no \nlonger consistent with cost causation principles because large loads configured in a \nBTMG arrangement with significant generation will raise cost shifting concerns \ncompared to loads pursuing smaller amounts of netting.214 The Commission also found \nthat such rules could lead to reliability and resource adequacy risks because PJM is \n \n210 See supra P 39. \n211 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n212 The Regional Access Charge is calculated by summing the Regional \nTransmission Revenue Requirements of all Participating Transmission Owners and \nApproved Project Sponsors and dividing the sum by the gross loads of all Participating \nTransmission Owners. See CAISO Tariff, app. F (Rate Schedules) (30.0.0), § 5.4. \n213 PJM Co-Location Order, 193 FERC ¶ 61,217 at PP 7, 186. \n214 Id. P 186."},{"page":61,"startToken":24574,"endToken":25002,"text":"Docket No. EL26-71-000 \n- 61 - \nobligated to serve transmission customers using BTMG, but does not consider such \ncustomers in transmission and resource adequacy planning.215 The Commission directed \nPJM to revise its retail BTMG rules, including establishing a MW threshold for the \namount of load at a particular electrical location that network customers may net by using \nBTMG.216 We are similarly concerned that CAISO’s Tariff allows Eligible Customers \nthat provide service to loads with BTMG to reduce their network service charges because \nthe definition of gross load, which is used to calculate the Regional Access Charge, \nexcludes load of a retail customer served by its own onsite generating unit or energy \nstorage device.217 CAISO should explain whether the Tariff remains just and reasonable \neven though it allows netting of BTMG from gross load for purposes of determining \nRegional Access Charges for loads with BTMG, or propose Tariff revisions. \nRecognizing potential impacts on existing customers, we note that CAISO may explain \nwhether current BTMG rules for customers that fall below a new MW materiality \nthreshold for the amount of load at a particular electrical location that network customers \nmay net using BTMG remain just and reasonable. \nD. \nExtending New Transmission Services to Eligible Customers Taking \nService on Behalf of Flexible Large Loads \n In response to the ANOPR, a number of commenters argue that certain large loads \nare able to limit their withdrawals from the transmission system under certain conditions. \nNamely, commenters observe that flexible large loads218 can quickly and verifiably adjust \ntheir consumption in response to system conditions or price signals.219 Commenters in \nthe ANOPR also observe that, where load studies and system planning consider the \nflexible nature of large loads, flexible large loads can potentially defer or reduce the need \n \n215 Id. \n216 Id. P 221. \n217 CAISO Tariff, § 26.1(c); id. app. A, Gross Load (3.0.0). \n218 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. \n219 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."},{"page":62,"startToken":25002,"endToken":25422,"text":"Docket No. EL26-71-000 \n- 62 - \nfor network upgrades, among other potential benefits.220 In recognition of this flexibility, \nmany commenters support new transmission services that reflect the operational \ncapabilities of flexible large loads, including interim NITS while network upgrades are \nconstructed and non-firm transmission service.221 \n We preliminarily find that CAISO’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.222 With limited exceptions, \ndaily transmission service with all energy treated as “new firm use” is the only type of \ntransmission service available in CAISO.223 While this remains a just and reasonable \noption for an Eligible Customer to take on behalf of a flexible large load, based on the \nrecord before us, we preliminarily find that new transmission services should be available \nto reflect the operational reality that large loads may use the transmission system to \ndiffering extents and certain large loads are willing and able to limit their use of the \ntransmission system under certain conditions.224 As explained above, the Commission \nfound that Eligible Customers taking transmission service on behalf of Eligible Load \nshould be allowed to choose a transmission service that aligns with their use of the \ntransmission system and therefore aligns the charges for service with the benefits \n \n220 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; California DWR November 21 ANOPR Comments at 5; LS \nPower November 21 ANOPR Comments at 5; Microsoft November 21 ANOPR \nComments at 10-11; National Grid November 21 ANOPR Comments at 19-20; OMS \nNovember 21 ANOPR Comments at 13-14; Southeast PIOs November 21 ANOPR \nComments at 50. \n221 See, e.g., Constellation November 21 ANOPR Comments at 24-25; Calibrant \nNovember 21 ANOPR Comments at 2-4; Critical Loop November 21 ANOPR \nComments at 2; Digital Power Network November 21 ANOPR Comments at 3; PIOs \nNovember 21 ANOPR Comments at 27-28; Splight November 21 ANOPR Comments at \n3-4. \n222 We direct this section only to CAISO because, unlike in other sections of this \norder, it appears that only CAISO’s Tariff is implicated because CAISO is the \ntransmission provider. \n223 See supra PP 19-20 (describing existing transmission service in CAISO). \n224 See supra P 103."},{"page":63,"startToken":25422,"endToken":25881,"text":"Docket No. EL26-71-000 \n- 63 - \nreceived.225 As the record suggests, Eligible Customers taking transmission service on \nbehalf of flexible large load also may be willing and able to limit their use of the \ntransmission system under certain conditions. As recognized in the ANOPR record, load \nflexibility can avoid inefficient and costly transmission system build-out.226 In addition, \ntransmission services that reflect that flexible large loads are willing and able to limit \ntheir withdrawals from the transmission system under certain conditions could help \ntimely interconnect flexible large loads.227 Entities in the CAISO footprint acknowledge \nthe importance of facilitating load flexibility.228 \n Therefore, we are concerned that CAISO’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. CAISO 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, CAISO \nshould explain whether the Tariff remains just and reasonable without (1) an interim \nnon-firm network transmission service while network upgrades are being constructed and \n(2) permanent firm and non-firm contract demand transmission services (transmission \nservice up to a specified MW quantity, i.e., the contract level, on a firm or non-firm \nbasis). In the alternative, CAISO may explain whether, given that CAISO does not offer \n \n225 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 199; PJM Co-Location \nRehearing Order, 195 FERC ¶ 61,209 at P 103. \n226 See supra P 103; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at \nPP 160, 177, 199 (finding that new transmission service options reflect a co-located \nload’s ability to limit withdrawals from the transmission system and potentially avoid \ncostly and inefficient transmission system buildout that may not be necessary). \n227 See supra P 103; see also PJM Co-Location Order, 193 FERC ¶ 61,217 at \nPP 201 (finding that the interim, non-firm transmission service will facilitate the “timely” \nprovision of transmission service and that “[t]his willingness to curtail would potentially \nallow them to obtain service more quickly”), 205 (recognizing that parties argue that co-\nlocated loads may be able to receive transmission service faster with use of a new, limited \ntransmission service product than they would if they selected NITS, to the extent that \nproviding NITS would require network upgrades that the limited transmission service \nwould not). \n228 See, e.g., California DWR November 10 ANOPR Comments at 5-7; see also \nCAISO November 21 ANOPR Comments at 15; PG&E November 21 ANOPR \nComments at 16 (recognizing benefits of large and co-located load flexibility)."},{"page":64,"startToken":25881,"endToken":26268,"text":"Docket No. EL26-71-000 \n- 64 - \nthe transmission services required by Order No. 888,229 CAISO’s existing transmission \nservice framework addresses the concerns described herein, or explain what specific \nchanges to its existing transmission service framework would effectively provide \ncomparable transmission service options for flexible large loads as in the PJM Co-\nLocation Order. Finally, we note that the Commission has found it just and reasonable \nthat, in order for an Eligible Customer to take interim NITS, firm contract demand \ntransmission service, and non-firm contract demand transmission service, an Eligible \nCustomer must have necessary control technologies and/or protection systems, which \nmay include a special protection scheme, to limit its energy withdrawals to its approved \nlevel.230 \nE. \nInterconnection Customers Serving Electrically Proximate Large Load \nand Co-Located Load \n In response to the ANOPR, a number of commenters agree that the ability to study \nnew load and new generation together, when physically or electrically proximate, \npresents system benefits and can help address the challenges posed by large load \nadditions.231 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.232 As a result, this can speed up the interconnection process for both large loads \nand generation, and shorten energization timelines,233 which commenters contend reduces \n \n229 See supra P 39. \n230 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n231 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. \n232 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. \n233 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."},{"page":65,"startToken":26268,"endToken":26631,"text":"Docket No. EL26-71-000 \n- 65 - \nuncertainty for both parties234 and “is necessary to match the pace of AI innovation in the \nUnited States.”235 CEBA also highlights that cost and timeline factors drive developers \nto submit multiple requests for price and timing discovery, which inflates queue volumes, \ndistorts demand and supply forecasts, and causes significant delays when projects \nwithdraw late after finding costs or energization timelines uneconomic.236 Other benefits \nto a joint study identified by commenters include improving load forecasting and siting \ndecisions237 and reducing the need for critical supply chain components.238 \n Commenters contend that current generator interconnection study processes may \nnot adequately capture generation and load, including by failing to model known \nelectrically proximate large load in base case assumptions, which may result in inaccurate \nstudies and inefficient system build-out.239 For example, Eolian states that in its \nexperience developing a project in PJM, the failure of the generator interconnection study \nprocess to reflect reasonably expected load conditions on the grid models triggered overly \ncostly network upgrades and caused the cancellation of generation project that could have \nreliably served adjacent load growth.240 \n Commenters in the ANOPR proceeding argue that the current state of the \ngenerator interconnection queue is not meeting the expeditious time frame needed to \nmatch the pace of large load additions and ensure the safe and reliable interconnection of \nthese loads.241 For example, Oracle states that one of the most significant and \n \n234 ClearPath November 21 ANOPR Comments at 4; CEBA November 21 \nANOPR Comments at 8. \n235 Microsoft November 21 ANOPR Comments at 8-9. \n236 CEBA November 21 ANOPR Comments at 8. \n237 ELCON November 21 ANOPR Comments at 5; Maryland Commission \nNovember 21 ANOPR Comments at 6-7. \n238 AEU November 21 ANOPR Comments at 13. \n239 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. \n240 Eolian May 19 ANOPR Comments at 10. \n241 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."},{"page":66,"startToken":26631,"endToken":26985,"text":"Docket No. EL26-71-000 \n- 66 - \nwidespread delays it encounters when siting data centers in the U.S. is access to sufficient \nenergy.242 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.243 Commenters contend that if large load interconnection proceeds more \nquickly than new generation can come online, the result could be price increases for \nconsumers.244 \n A number of commenters support expedited interconnection studies for new \ngeneration paired with load.245 Some commenters argue that one solution to generator \ninterconnection delays may be the creation of time-limited or conditional interconnection \nservice for generators serving large loads, which could require less time for initial \ngenerator interconnection studies and improve speed to power.246 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.247 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 \n \n242 Oracle November 21 ANOPR Comments at 1. \n243 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)). \n244 AEP December 5 ANOPR Comments at 1-2; OPSI November 21 ANOPR \nComments at 6-7, 11. \n245 See, e.g., DTE November 21 ANOPR Comments at 8; ENGIE November 21 \nANOPR Comments at 4; International Energy Credit Association November 21 ANOPR \nComments at 8; Meta November 21 ANOPR Comments at 5-6; Ohio FEA November 21 \nANOPR Comments at 5. \n246 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. \n247 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."},{"page":67,"startToken":26985,"endToken":27364,"text":"Docket No. EL26-71-000 \n- 67 - \nunreasonable not to fully utilize existing infrastructure and proven reliability paths while \nnew load waits for service.248 \n1. \nJurisdiction \n The Commission’s statutory authority includes jurisdiction over the wholesale sale \nand transmission of electricity in interstate commerce, including the facilities used for \nsuch sale and transmission.249 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.250 In the PJM Co-Location Order, the Commission observed that a generator’s \ninterconnection to the interstate transmission system “does not fall outside of the \nCommission’s jurisdiction merely because there is [c]o-[l]ocated [l]oad behind the \ngenerator’s point of interconnection.”251 By the same token, the Commission retains \njurisdiction over a generator’s interconnection even where the generator plans to serve an \nelectrically proximate large load. \n We recognize that states have exclusive authority over resource planning and the \ngeneration mix within their boundaries.252 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 \n \n248 Constellation June 5 ANOPR Comments at 8-9. \n249 16 U.S.C. § 824(b)(1). \n250 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.”). \n251 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 171. \n252 See, e.g., Citizens Action Coal. of Ind., Inc. v. FERC, 125 F.4th at 238 (citing \n16 U.S.C. § 824(b)(1))."},{"page":68,"startToken":27364,"endToken":27746,"text":"Docket No. EL26-71-000 \n- 68 - \nrequiring generator interconnection services that allow certain generating facilities to \ninterconnect more quickly through the use of provisional interconnection service and \nsurplus interconnection service,253 and has approved interconnection processes that allow \ncertain generating facilities to interconnect more quickly by replacing a retiring existing \ngenerating facility.254 \n2. \nDefinitions \n For purposes of this order, it appears to be reasonable to use the term “electrically \nproximate large load” to mean a large load, as defined in this order,255 that is sufficiently \nelectrically close to the interconnection customer’s requested point of interconnection, \nsuch that the impact on the transmission system of the combination of the generating \nfacility and the load, with the exception of the transmission facilities between the two, \nwill be effectively the same as if they were located at the same substation (e.g., large load \nthat is located no more than two substations away from the generating facility). We will \nconsider proposed revisions to this definition that ensure it is appropriately tailored to \nCAISO’s transmission system. \n3. \nTariff Provisions \n We preliminarily find that CAISO’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,256 that has a high peak load (i.e., large co-located loads that are 50 MW or \ngreater).257 Specifically, we preliminarily find that CAISO’s Tariff appears to be unjust \nand unreasonable because it lacks a generator interconnection study process and/or \n \n253 Reform of Generator Interconnection Procs. & Agreements, Order No. 845, \n163 FERC ¶ 61,043, at PP 438, 467 (2018), order on reh’g & clarification, Order No. \n845-A, 166 FERC ¶ 61,137, order on reh’g & clarification, Order No. 845-B, 168 \nFERC ¶ 61,092 (2019); Order No. 2023, 184 FERC ¶ 61,054 at P 1436; PJM \nInterconnection, L.L.C., 190 FERC ¶ 61,083 (2025). \n254 See, e.g., PJM Interconnection, L.L.C., 194 FERC ¶ 61,079 (2026); \nMidcontinent Indep. Sys. Operator Inc., 167 FERC ¶ 61,146 (2019). \n255 See supra P 57. \n256 See supra P 88. \n257 We note that generator interconnection service in and of itself does not convey \ntransmission service."},{"page":69,"startToken":27746,"endToken":28233,"text":"Docket No. EL26-71-000 \n- 69 - \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 CAISO’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,258 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,259 thereby potentially \nreducing the need for network upgrades, which can accelerate the generator \ninterconnection process.260 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 \n \n258 PJM Co-Location Rehearing Order, 195 FERC ¶ 61,209 at P 480. \n259 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. \n260 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.”)."},{"page":70,"startToken":28233,"endToken":28665,"text":"Docket No. EL26-71-000 \n- 70 - \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.261 \n As commenters in the ANOPR proceeding have recognized, the status quo may \nresult in inefficient and unnecessary development of infrastructure, which leads to \nunnecessarily higher network upgrade costs that may result in unjust and unreasonable \nrates.262 The Commission has already determined in the PJM Co-Location Order that \nwithout the new transmission services that reflect the operational dynamics of co-location \narrangements, there could be unnecessary, costly, and inefficient network upgrades, \nincreasing network upgrade costs.263 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.264 \n SPP recognized this problem and submitted an FPA section 205 filing to \nimplement a new, interim, generator interconnection service and related generator \n \n261 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. \n262 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. \n263 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 177 (“[F]or Eligible \nCustomers taking service on behalf of Co-Located Loads that do not reserve \ntransmission . . . requiring such Eligible Customers to take NITS on behalf of these \nCo-Located Loads may in some circumstances result in costly and inefficient \ntransmission system buildout that may not be necessary if such Eligible Customers are \nwilling and able to take a transmission service that requires fewer Network Upgrades to \nprovide, and therefore may result in lower Network Upgrade costs, than would NITS.”). \n264 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)."},{"page":71,"startToken":28665,"endToken":29100,"text":"Docket No. EL26-71-000 \n- 71 - \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.265 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.”266 We do not expect or propose that CAISO 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 CAISO’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.267 To the extent that the interconnection customer’s \ngenerating facility is serving an electrically proximate large load, we believe that the \ngenerator interconnection service should be of an interim nature until the interconnection \ncustomer obtains Energy Resource Interconnection Service (ERIS) or Network Resource \nInterconnection Service (NRIS). To the extent that the interconnection customer’s \ngenerating facility is serving a large co-located load, it may be reasonable for the \ngenerator interconnection service to be permanent because there will be no injections \nonto the transmission system and therefore it does not present operational or planning \nrisks for reliability. \n 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 \n \n265 SPP HILL Order, 194 FERC ¶ 61,031. \n266 Id. P 64. \n267 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 CAISO’s transmission system \nmay warrant consideration of a more limited definition of electrically proximate. See \nDuke November 21 ANOPR Comments at 21-22; DTE November 21 ANOPR \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."},{"page":72,"startToken":29100,"endToken":29535,"text":"Docket No. EL26-71-000 \n- 72 - \nprotection scheme, that ensure that the net injection does not exceed the amount in the \nexisting generator interconnection agreement.268 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.269 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.270 It may be reasonable for such a load-limited \ngenerator interconnection service to be or not to be of an interim nature. We invite \nCAISO and/or Participating Transmission Owners, in responding to this order or in an \nFPA section 205 filing, to submit original proposals designed to address the concerns \nexpressed herein and tailored to their unique circumstances. \n 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 CAISO’s current \ngenerator interconnection process failing to keep pace with the new large loads seeking to \nbe integrated onto CAISO’s transmission system.271 We preliminarily find that this \noutcome may be unjust and unreasonable because reliance on CAISO’s current generator \ninterconnection processes for generating facilities serving electrically proximate large \nloads or large co-located loads could result in unnecessary interconnection delays, \n \n268 See Constellation June 5 ANOPR Comments at 1-2, 10-13. \n269 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”). \n270 See MISO November 21 ANOPR Comments at 13; see also MISO TOs April 3 \nANOPR Comments at 13-14. \n271 See Helion November 21 ANOPR Comments at 1 (noting interconnection \ndelays are the biggest barrier to adding new generation); Oracle November 21 ANOPR \nComments at 1 (noting significant delays in access to sufficient energy for data centers); \nOPSI November 21 ANOPR Comments at 11 (explaining that expedited study \nencourages loads to bring their own generation); Enchanted Rock November 21 ANOPR \nComments at 4; Microsoft November 21 ANOPR Comments at 8-9."},{"page":73,"startToken":29535,"endToken":29988,"text":"Docket No. EL26-71-000 \n- 73 - \nunnecessary network upgrades, and an otherwise inefficient expansion of the \ntransmission system, imposing unnecessary delays and costs on transmission customers. \n CAISO 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. \n Given that generator interconnection service in and of itself does not convey \ntransmission service, we encourage CAISO to consider, in responding to these concerns, \nwhat type of transmission service an Eligible Customer will need to take on behalf of the \nelectrically proximate large load or large co-located load.272 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.273 \nF. \nInformational Report \n The rapid addition and proliferation of large loads without commensurate \nadditions of supply or demand-side resources presents resource adequacy concerns. As \ndiscussed above and highlighted in the ANOPR, the growth of demand, and the speed of \nsuch growth, is driven in large part by the interconnection of large loads. While not \nexpressly contemplated in the ANOPR, commenters highlight the strain rapid demand \ngrowth is putting on resource adequacy in many regions.274 Indeed, the relative speed \n \n272 See SPP HILL Order, 194 FERC ¶ 61,031 at P 34. \n273 PJM Co-Location Order, 193 FERC ¶ 61,217 at P 206. \n274 See, e.g., Entergy November 21 ANOPR Comments at 29-30; Eolian \nNovember 21 ANOPR Comments at 16-17; Industrial Customers November 21 ANOPR"},{"page":74,"startToken":29988,"endToken":30397,"text":"Docket No. EL26-71-000 \n- 74 - \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.275 We are concerned that CAISO and load serving entities \nare unable to plan adequate generation to serve all load at the pace such load seeks to \nconnect. \n We recognize that RTOs/ISOs are engaging in efforts to more rapidly interconnect \ngeneration that is needed to serve this unprecedented growth in load. In particular, \nCAISO has made revisions to its Tariff through its Interconnection Process Enhancement \ninitiative that have enhanced the coordination of resource procurement and \ninterconnection, improved resource planning and transmission planning, and streamlined \ngenerator interconnection and Deliverability allocation procedures.276 While we are \nencouraged by the implementation of such processes to ensure resource adequacy and \nfaster interconnection, and recognize that CAISO continues to engage in Interconnection \nProcess Enhancements,277 we remain concerned that these efforts may fall short in light \nof generator retirements and tightening supply conditions. \n Accordingly, we direct CAISO to submit in Docket No. EL26-71-000, 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. Given that the CPUC has primary responsibility for resource \nadequacy within the CAISO footprint, CAISO should provide information on any \nongoing initiatives and coordination with the CPUC and other relevant state agencies \nrelated to ensuring generation adequacy. We also strongly encourage new proposals to \n \nComments at 24-26; R Street November 21 ANOPR Comments at 1; South Dakota \nCommission November 13 ANOPR Comments at 5; Talen December 5 ANOPR Reply \nComments at 7. \n275 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. \n276 See Cal. Indep. Sys. Operator Corp., 191 FERC ¶ 61,218 (2025); Cal. Indep. \nSys. Operator Corp., 189 FERC ¶ 61,195 (2024); Cal. Indep. Sys. Operator Corp., \n184 FERC ¶ 61,069 (2023). \n277 CAISO has developed a final proposal for its Interconnection Process \nEnhancements 5.0 initiative, which was approved by the Board on April 30, 2026. See \nCAISO, Initiative: Interconnection Process Enhancements 5.0, \nhttps://stakeholdercenter.caiso.com/StakeholderInitiatives/Interconnection-process-\nenhancements-5-0."},{"page":75,"startToken":30397,"endToken":30865,"text":"Docket No. EL26-71-000 \n- 75 - \nthe extent necessary to address these concerns. The informational report must include a \ndetailed schedule of key milestones, such as stakeholder or CAISO Board votes, that \nincludes the estimated date on which CAISO expects to file any such proposals with the \nCommission. Additionally, as part of this informational report, we direct CAISO to \nidentify any ongoing stakeholder processes that aim to increase the pace of adding \ngenerating capacity in the CAISO region. The informational report must include a \ndetailed schedule of such initiatives, including timing of the stakeholder process and \ndates of any anticipated filings with the Commission. \nIV. \nBriefing Questions \n We note that large loads, including data centers, are actively working with \ntransmission owners and other relevant entities to interconnect to, and to take \ninterconnection and/or transmission service from, the transmission system and may be at \nvarying stages of that process. We appreciate that different large loads are currently at \ndifferent stages of that process. We also understand that large loads and Eligible \nCustomers taking transmission service on behalf of large loads are negotiating, entering \ninto, and/or have executed various agreements related to interconnecting to the \ntransmission system and/or the provision of transmission service. We direct further \nbriefing regarding how CAISO and the Participating Transmission Owners, in responding \nto the order to show cause, should protect existing commercial arrangements including: \n(1) what would be a reasonable implementation period to ensure minimal disruption to \nsuch existing commercial arrangements, and (2) how to allow a reasonable amount of \ntime to finalize ongoing agreements that are nearing completion as of the date such tariff \nprovisions are filed with the Commission. \n Today’s order proposes, as part of a potential replacement rate, to establish new \ntransmission services that recognize flexible large loads’ ability and willingness to limit \ntheir use of the transmission system under certain conditions. As we assess this proposal, \nwe also consider how these new transmission services might affect other parts of \nCAISO’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? \n Today’s order preliminarily finds that CAISO’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"},{"page":76,"startToken":30865,"endToken":31284,"text":"Docket No. EL26-71-000 \n- 76 - \nunreasonable cost shifts among transmission customers related to network upgrade costs \nrequired for large loads. Further, please include information on what an appropriate \nminimum level of cost recovery and financial security from an Eligible Customer would \nbe under any such agreements. \n Today’s order preliminarily finds that CAISO’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 CAISO to explain whether the \nTariff remains just and reasonable without provisions that (1) require the evaluation of \nalternative transmission technologies in studies for the provision of transmission service, \nusing models that are capable of evaluating the transmission system to accurately account \nfor advanced transmission technologies, in all instances, without the need for a request \nfrom the Eligible Customer seeking transmission service on behalf of large load; and (2) \nif traditional network upgrades are selected instead of alternative transmission \ntechnologies, inclusion in the study report to the Eligible Customer seeking transmission \nservice on behalf of large load of a sufficiently clear demonstration of why alternative \ntransmission technologies are not feasible (i.e., would not resolve reliability violations \nidentified or meet the relevant planning criteria) or would not result in lower costs or a \nfaster timeline for accommodating the transmission service request. As noted above, to \nthe extent stakeholders believe that specific characteristics of providing transmission \nservice to Eligible Customers on behalf of large loads warrant requirements beyond those \ncontemplated here, we seek further briefing. \n Today’s order preliminarily finds that CAISO’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 CAISO allow an interconnection customer’s \ngenerating facility serving electrically proximate large load or large co-\nlocated load to participate in CAISO’s energy and ancillary services \nmarket, and if CAISO were to allow them to participate, what restrictions \nor mitigation would CAISO apply? \nb. To the extent that CAISO 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 CAISO account \nfor the generating facilities serving electrically proximate large load or \nlarge co-located load in the resource adequacy construct? If applicable, \nwould CAISO allow the generating facilities serving electrically proximate"},{"page":77,"startToken":31284,"endToken":31723,"text":"Docket No. EL26-71-000 \n- 77 - \nlarge load or large co-located load to participate in CAISO’s capacity \nmarket? If so, would CAISO accredit these generating facilities using the \nsame method as other CAISO 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. EL26-71-000 as discussed in the body of this order. \n(B) \nCAISO and the Participating Transmission Owners are hereby directed, \nwithin 60 days of the date of the order, either: (1) to show cause as to why the Tariff \nremains just and reasonable and not unduly discriminatory or preferential; or (2) to \nexplain what changes to the Tariff it believes would remedy the identified concerns if the \nCommission were to determine that the Tariff has in fact become unjust and unreasonable \nor unduly discriminatory or preferential and, therefore, proceeds to establish a \nreplacement Tariff. \n(C) \nCAISO 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. EL26-71-000 \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 CAISO’s and the \nParticipating Transmission Owners’ filing, addressing either or both of: (1) whether the \nTariff remains just and reasonable and not unduly discriminatory or preferential; and (2) \nif not, what changes to the Tariff should be implemented as a replacement rate. \n(F) \nThe Secretary shall promptly publish in the Federal Register a notice of the \nCommission’s initiation of the proceeding under section 206 of the FPA in Docket No."},{"page":78,"startToken":31723,"endToken":31820,"text":"Docket No. EL26-71-000 \n- 78 - \nEL26-71-000. \n \n \n(G) \nThe refund effective date in Docket No. EL26-71-000 pursuant to section \n206 of the FPA shall be the date of publication in the Federal Register of the notice \ndiscussed in Ordering Paragraph (F) above. \nBy the Commission. Chairman Swett is concurring with a separate statement attached. \n \n \n \n Commissioner Rosner is concurring with a separate statement \n attached. \n Commissioner See is concurring with a separate statement attached. \n Commissioner Chang is concurring with a separate statement \n attached. \n Commissioner LaCerte is concurring with a separate statement \n attached. \n \n( S E A L ) \n \n \n \n \nCarlos D. Clay, \nDeputy Secretary."},{"page":79,"startToken":31820,"endToken":32051,"text":"Docket No. EL26-71-000 \n- 79 - \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 Corporation278 \nAmerican Public Gas Association \nAmerican Public Power Association (APPA) \nAmerican Terawatt, Inc. (American Terawatt) \nAmerican Transmission Company LLC (ATC)279 \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 \n278 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. \n279 ATC submitted comments on behalf of itself and its corporate manager ATC \nManagement Inc."},{"page":80,"startToken":32051,"endToken":32252,"text":"Docket No. EL26-71-000 \n- 80 - \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 (CAISO) \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)280 \nDigital Energy Council \nDigital Power Network \nDistributed Capacity Parties281 \nDTE Electric Company (DTE) \nDr. Elisa Nelson \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 \n280 The Illinois Attorney General joined the Joint Consumer Advocates in filing \nreply comments. \n281 Distributed Capacity Parties include: Clovereleaf Infrastructure; Spark \nCommunity Investment d/b/a Sparkfund; and Voltus, Inc."},{"page":81,"startToken":32252,"endToken":32479,"text":"Docket No. EL26-71-000 \n- 81 - \nEnergy Trading Institute \nENGIE North America, Inc. (ENGIE) \nEntergy Services, LLC (Entergy)282 \nEnvironmental Law & Policy Center \nEolian L.P. (Eolian) \nEquinix, Inc. \nesVolta, LP \nETX Upstream, LLC \nEversource Energy283 \nExelon Corporation (Exelon)284 \nFervo Energy Company (Fervo) \nFirstEnergy Service Company285 \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 \n282 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. \n283 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. \n284 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. \n285 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":82,"startToken":32479,"endToken":32790,"text":"Docket No. EL26-71-000 \n- 82 - \nHelion Energy (Helion) \nHerbert Schrayschuen \nHeron Power Electronics Company \n \nIndiana Energy Association \nIndicated PJM Transmission Owners286 \nIndustrial Customer Organizations (Industrial Customers)287 \nInformation Technology Industry Council \nInfrastructure Masons, Inc. (Infrastructure Masons) \nInstitute for Progress \nInternational Energy Credit Association \nInvenergy288 \n \n286 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. \n287 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 \n288 Invenergy includes: Invenergy Wind Development North America LLC, \nInvenergy Solar Development North America LLC, and Invenergy Thermal Development \nHoldings LLC."},{"page":83,"startToken":32790,"endToken":33064,"text":"Docket No. EL26-71-000 \n- 83 - \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 Parties289 \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)290 \n \n289 Load Flexibility Parties include: Enerwise Global Technologies, LLC d/b/a \nCPower, Enel North America, Inc., and Voltus, Inc. \n290 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":84,"startToken":33064,"endToken":33375,"text":"Docket No. EL26-71-000 \n- 84 - \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)291 \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 Systems292 \nNew England Public Systems293 \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 \n291 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. \n292 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. \n293 New England Public Systems include: Connecticut Municipal Electric \nCooperative, Massachusetts Municipal Wholesale Electric Company, and Vermont"},{"page":85,"startToken":33375,"endToken":33609,"text":"Docket No. EL26-71-000 \n- 85 - \nNew Mexico Public Regulation Commission (New Mexico Commission) \nNew York Independent System Operator, Inc. \nNew York State Department of State Utility Intervention Unit (NY UIU) \nNew York Public Service Commission \nNew York State Reliability Council \nNew York Transmission Owners294 \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 (PG&E) \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 Corporation295 \n \nPublic Power Supply Authority. \n294 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. \n295 PPL Corporation submitted comments on behalf of the PPL Companies, which"},{"page":86,"startToken":33609,"endToken":33846,"text":"Docket No. EL26-71-000 \n- 86 - \nPrime Mover Institute \nPSEG Companies296 \nPublic Citizen, Inc. \nPublic Interest Organizations (PIOs)297 \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)298 \nSouthern California Edison Company (Southern California Edison) \nSouthern Companies299 \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. \n296 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. \n297 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. \n298 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. \n299 Southern Companies include: Georgia Power Company, Alabama Power \nCompany, and Mississippi Power Company."},{"page":87,"startToken":33846,"endToken":34118,"text":"Docket No. EL26-71-000 \n- 87 - \nSouthwest Power Pool Transmission Owner Group300 \nSplight Inc. (Splight) \nState Entities301 \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 \nMembers302 \nU.S. Representatives303 \nU.S. Senate Committee on Energy and Natural Resources \nU.S. Senators304 \n \n300 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. \n301 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. \n302 Submitted by Frank Pallone, Jr. (Ranking Member) and Kathy Castor (Ranking \nMember, Subcommittee on Energy). \n303 The U.S. Representatives that submitted comments include: Suhas \nSubramanyam, John W. Mannion, Mike Quigley, and Donald S. Beyer Jr. \n304 The U.S. Senators that submitted comments include: Edward J. Markey, Chris \nVan Hollen, Elizabeth Warren, Peter Welch, Raphael Warnock, Richard Blumenthal, and"},{"page":88,"startToken":34118,"endToken":34159,"text":"Docket No. EL26-71-000 \n- 88 - \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 \nWisconsin Electric Company \nWisconsin Public Service Corporation \n \n \nAdam B. Schiff."},{"page":89,"startToken":34159,"endToken":34341,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nCalifornia Independent System Operator Corporation \nCitizen S-Line Transmission LLC \nCitizens Sunrise Transmission LLC \nCitizens Sycamore-Penasquitos Transmission LLC \nCity of Anaheim, California \nCity of Azusa, California \nCity of Banning, California \nCity of Colton, California \nCity of Pasadena, California \nCity of Riverside, California \nDCR Transmission, L.L.C. \nDesertLink, LLC \nGridLiance West LLC \nHorizon West Transmission, LLC \nLS Power Grid California, LLC \nMorongo Transmission LLC \nPacific Gas and Electric Company \nSan Diego Gas & Electric Company \nSouthern California Edison Company \nStartrans IO, L.L.C. \nSunZia Transmission, LLC \nTrans Bay Cable LLC \nValley Electric Association, Inc. \nViridon Path 15, LLC \nWestern Area Power Administration \nDocket No. EL26-71-000 \n \n \n(Issued June 18, 2026) \n \nSWETT, Chairman, concurring: \n \n \nToday, we take historic action to push our country’s electric markets and economy \ninto the future—a future of fair cost allocation, unprecedented transparency for the \nAmerican ratepayer, respect for states’ rights, efficient markets and speed to power. Last \nOctober, Secretary Wright articulated the monumental, generational and “urgent” \nchallenge FERC must solve for our country when he directed us to develop “reforms to"},{"page":90,"startToken":34341,"endToken":34781,"text":"Docket No. EL26-71-000 \n \n- 2 - \n \nensure the timely and orderly interconnection of large loads to the transmission system.”1 \nI strongly agree. And now, through this suite of six orders, we deliver. \n \nSimply put, the show cause orders the Commission issues today to each of the six \nelectric markets subject to its jurisdiction find that the status quo across much of the \ncountry is not good enough.2 Nowhere close. The record prompted by the Secretary’s \nANOPR leaves no doubt that most of the markets (and their existing rules) are inherently \nslow and prohibitive of the dexterity necessary to adapt to and power societal evolution—\nwhether brought about by technological innovation or sustaining the great industrial \neconomy that anchors America. \n \nI wholeheartedly, fully concur with these orders, which we carefully crafted to \nexecute upon the problems the Secretary identified in a manner that is quick, efficient, \nand legally durable. I write separately to highlight certain considerations underlying the \nCommission’s procedural approach to delivering on the ANOPR and to today’s orders. \n \nBased on my analysis of the extensive record and numerous ongoing substantive \nstakeholder interactions, I have determined that the most productive way to “build upon \nthe[] principles”3 in the ANOPR and “work expeditiously”4 towards a solution is to issue \nindividualized orders to show cause to each market.5 That is so for two main reasons. \n \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). \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"},{"page":91,"startToken":34781,"endToken":35226,"text":"Docket No. EL26-71-000 \n \n- 3 - \n \n \nFirst, the record the Commission collected in response to the challenges identified \nin the ANOPR and subsequent resulting developments indicate that an approach that \nhonors the ANOPR principles but accounts for widening regional variation may now be \nmore efficient than a one-size-fits-all rule.6 The world has changed a great deal since last \nOctober. The ANOPR itself, including the articulated principles, appears to have shifted \nthe playing field and prompted great progress across several electric markets. This \nchange (and the Commission’s alignment with the Secretary) is well illustrated by a \nnumber of landmark orders approving several market new constructs that we issued since \nOctober, which together operationalize the Secretary’s principles and laid groundwork \nfor meaningful reform and today’s actions.7 While working to develop those orders, the \nCommission has simultaneously devoted significant attention to evaluating the various \nprocedural paths through which we might comprehensively deliver. \n \nIndividual show cause proceedings will allow the Commission to ensure that \nsolutions to the problems the Secretary identified are tailored to the specific, varied \ncircumstances and market constructs of each region. Indeed, a careful review of today’s \nsix orders reveals the many ways in which those orders are customized for each market’s \nunique circumstances and progress (or lack thereof) towards serving large load. To name \njust a few examples, the orders recognize ongoing stakeholder processes in various \nregions and are adapted to existing tariff provisions concerning large and co-located \nloads; account for regional variances in allocating rights and responsibilities among \nRTOs/ISOs and the transmission owners; leave room for each market to tailor operational \nrequirements for large loads that are particular to their region; and otherwise account for \nincumbent regional differences on topics such as cost allocation and cost transparency, \nstudy processes, and network upgrade procedures. \n \nProceeding via show cause proceedings will also allow the markets (and their \nrespective transmission owners) to explain, in the first instance, how to address the \nCommission’s concerns. These entities have the deepest understanding of their \n \nadministrative law that the decision whether to proceed by rulemaking or adjudication \nlies within the broad discretion of the agency.”). \n6 “[T]he Commission may rely on ‘generic’ or ‘general’ findings of a systemic \nproblem to support imposition of an industry-wide solution.” Interstate Nat. Gas Ass’n \nof Am. v. FERC, 285 F.3d 18, 37 (D.C. Cir. 2002) (internal citations omitted). However, \nthe Commission “has long allowed different regional transmission organizations to \nfollow different rules, in recognition of regional variations including potential differences \nin ‘geographic size and location.’” Cent. Hudson Gas & Elec. Corp. v. FERC, 138 F.4th \n531, 539 (D.C. Cir. 2025) (internal citations omitted). \n7 See id. P 2 & nn.6-11."},{"page":92,"startToken":35226,"endToken":35689,"text":"Docket No. EL26-71-000 \n \n- 4 - \n \nrespective regions and are best positioned to implement solutions we identified, in the \nmost expeditious manner. The Commission will promptly evaluate their responses to \ntoday’s orders, and, with input from stakeholders, swiftly establish appropriate reforms. \n \nSecond, proceeding via individual show cause orders will allow the Commission \nto act more quickly than through traditional rulemaking. Notice-and-comment \nrulemaking may not capitalize upon individual market progress prompted since October \nand would be unduly time-consuming,8 as it also inevitably would require the additional \nsteps of accommodating the regional variations of the approach we take today. \nRulemaking efforts can be particularly inefficient when, as here, they risk incubating \nuncertainty after progress has begun, and diverting scarce stakeholder resources away \nfrom other endeavors, such as the development of market-specific reforms submitted to \nthe Commission under section 205 of the Federal Power Act (FPA). (To be clear, we \nvery much encourage 205 submissions encapsulating the principles we articulate in the \n206s, and with all due deliberate haste.) \n \nFurthermore, rulemaking requires a lengthy series of steps before the proposed \nreforms would actually take effect—e.g., a NOPR, then a final rule, then potential orders \non rehearing, and then a “compliance” process in which affected parties make filings (or, \nmore likely, multiple rounds of filings) explaining how they intend to implement the rule. \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 \n \n8 See, e.g., Comments of Talen Energy Corporation, Docket No. RM26-4, at 5-6 \n(filed Nov. 21, 2025). \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"},{"page":93,"startToken":35689,"endToken":35952,"text":"Docket No. EL26-71-000 \n \n- 5 - \n \nof the years-long delays in implementation that might be expected if the Commission \nelected to proceed via a NOPR. By contrast, we expect that individual show cause \nproceedings for each of the RTO/ISOs will enable the Commission to spearhead lasting \nreform much more expeditiously. \n \nThe six markets together cover nearly two-thirds of load subject to Commission-\njurisdictional rates, and therefore focusing initially on those regions is a prudent first step. \nBut I am under no illusion that the challenges discussed in today’s orders are somehow \nunique to the RTO/ISO regions. Our actions today do not foreclose the possibility of a \nfuture rulemaking, and nor do they prevent us from acting on filings made under sections \n205 and 206 of the FPA. I encourage transmission providers and other stakeholders \noutside RTO/ISO regions to make individual filings to address the issues we discuss \ntoday. \n \nFERC is no longer the sleepy, responsive agency of the past—our country cannot \nafford for it to be. This is a time for the best thinkers we have to collaborate on solving \nour biggest problems, and thus it is my great honor to deliver a solution that honors the \nSecretary’s goals. For these reasons, I respectfully concur. \n \n \n________________________ \nLaura V. Swett \nChairman \n \n \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":94,"startToken":35952,"endToken":36184,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nCalifornia Independent System Operator Corporation \nCitizen S-Line Transmission LLC \nCitizens Sunrise Transmission LLC \nCitizens Sycamore-Penasquitos Transmission LLC \nCity of Anaheim, California \nCity of Azusa, California \nCity of Banning, California \nCity of Colton, California \nCity of Pasadena, California \nCity of Riverside, California \nDCR Transmission, L.L.C. \nDesertLink, LLC \nGridLiance West LLC \nHorizon West Transmission, LLC \nLS Power Grid California, LLC \nMorongo Transmission LLC \nPacific Gas and Electric Company \nSan Diego Gas & Electric Company \nSouthern California Edison Company \nStartrans IO, L.L.C. \nSunZia Transmission, LLC \nTrans Bay Cable LLC \nValley Electric Association, Inc. \nViridon Path 15, LLC \nWestern Area Power Administration \nDocket No. EL26-71-000 \n \n \n(Issued June 18, 2026) \n \nROSNER, Commissioner, concurring: \n \n \nThe electric industry is in the midst of changes not seen in a generation. \nCompared to more traditional load growth, the large loads seeking to connect to the grid \ntoday are larger, sometimes by orders of magnitude, and more concentrated. They also \nexhibit different operational characteristics, such as the ability to quickly change their \nenergy consumption, sometimes in seconds. Often, these large loads seek to connect to \nthe grid as quickly as possible. And because of these dynamics, large loads are rapidly \ndriving the need for new transmission infrastructure and energy supply. This creates new \nchallenges that, if unaddressed, could jeopardize the reliability and affordability of the \ngrid on which we all depend."},{"page":95,"startToken":36184,"endToken":36656,"text":"Docket No. EL26-71-000 \n- 2 - \n \nToday, we are taking an important step toward addressing these challenges. We \nare opening a dialogue with each of the six RTO/ISOs on a series of reforms that are \ntailored to address the unique reliability and affordability challenges posed by large load \ngrowth and the infrastructure buildout needed to serve dramatically growing demand. \nInformed by the record developed in response to the Secretary of Energy’s October 2025 \nANOPR,1 and by innovative proposals that stakeholders have filed with the Commission \nunder FPA section 205, today’s orders are aimed at ensuring that the grid remains reliable \nand affordable for all customers, especially residential customers. It is also crucial that \nwe unlock the immense economic opportunity that once-in-a-generation growth \nrepresents. While each order’s specific focus varies according to the progress that each \nRTO/ISO has made, our actions today fit broadly into four key pillars that, taken \ntogether, provide a foundation for durable reform. Today, we are: (1) Protecting \nConsumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering \nInnovation (see Figure 1). I write separately to explain how. \n***** \n \nProtecting Consumers: Today’s orders include key protections that promote \naffordability. First, today’s orders require “Cost Recovery Agreements”, which are \ndesigned to ensure that large loads pay their fair share of the costs incurred to serve them, \nregardless of whether the large load comes online as planned. Thus, if new infrastructure \nis built to accommodate a data center, and that data center doesn’t show up, residential \ncustomers are not left on the hook to pay the costs. Cost Recovery Agreements prevent \nthose costs from being shifted to residential customers. Depending on how they are \nstructured, Cost Recovery Agreements can also address the potentially uneven pacing of \nnew infrastructure costs, where grid upgrade costs may hit customer bills before the large \nload is fully online and energized. Data centers have committed to paying their own \nway.2 Today, with “Cost Recovery Agreements,” we are taking steps to ensure that those \ncommitments are honored. I note, however, that the door remains open to other creative, \nregionally-specific ideas to protect consumers. If there are other ways to accomplish that \ngoal, I welcome those proposals. \n \nAnother win for consumers is requiring RTO/ISOs to consider grid enhancing \ntechnologies (GETs), including dynamic line ratings, when adding new large loads to the \ngrid. GETs are technologies that squeeze more juice out of the existing grid, reducing the \nneed for expensive upgrades and speeding up the time connect. Ensuring that RTO/ISOs \n \n1 U.S. Dep’t of Energy, Secretary of Energy Chris Wright, Direction that the \nCommission Initiate Rulemaking Procedures and Proposal Regarding the Interconnection \nof Large Loads Pursuant to the Secretary’s Authority Under Section 403 of the \nDepartment of Energy Organization Act (Oct. 23, 2025). \n2 See Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026)."},{"page":96,"startToken":36656,"endToken":37067,"text":"Docket No. EL26-71-000 \n- 3 - \nconsider GETs in the planning process—and if GETs are not used, explain why—not \nonly helps new large loads get connected more quickly, but is also a commonsense step \ntowards saving all consumers money. Put differently, today’s orders will help us \nunderstand if we are leaving efficiencies on the table, an outcome we cannot afford. \n \nSafeguarding Reliability: Today’s orders safeguard reliability. They help ensure \nthat RTO/ISOs use study procedures and operational requirements that reflect large \nloads’ unique characteristics and the reliability impacts of connecting them to the grid. \nThose novel characteristics and reliability impacts are well-documented, and it is not \nclear if existing study procedures or operational requirements account for them. Clear, \ncomprehensive, and specifically tailored study procedures and operational requirements \nare needed, such as enhanced data reporting and telemetry to increase visibility into how \nthese loads interact with the grid, and today’s orders represent progress towards this goal. \n \nFinally, although not part of today’s orders, I want to highlight NERC’s ongoing \nefforts to establish registration criteria for large computational loads and to develop \nreliability standards.3 NERC’s goal is to finish the first phase of this critical work this \nyear. It is essential that NERC meet this deadline. I encourage all stakeholders to \nparticipate in NERC’s process. \n \nEnhancing Transparency: Today’s orders provide regulators—the Commission \nand, critically, our state partners—and customers with data on how connecting large \nloads to the grid affects bills. Today’s orders embody a commonsense approach: if a \nNetwork Upgrade is built to connect a large load to the grid, consumers should know who \nthat upgrade was built for and what it cost. \n \nTransparency is important because “who pays?” has been and continues to be a \nfraught and contentious question for large load interconnection. Stakeholders, including \nstate regulators and the ratepayers that they represent, must know the costs, for whom \nthey are being incurred, and how they are being allocated, to know that everyone is \npaying their fair share. Today’s orders ensure that this information is public, accessible, \nand clear. State regulators in more than half of the country have enacted large load \ntariffs.4 Our action today helps them as they continue their critically important work. \n \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":97,"startToken":37067,"endToken":37482,"text":"Docket No. EL26-71-000 \n- 4 - \n \nThe Commission’s action today also addresses speculative load interconnection \nrequests, which clog up load interconnection queues, divert resources, and distort \nforecasts. Under current rules, data centers can (and are incentivized to) “shop around” \ntheir prospective projects with different utilities to identify the fastest and cheapest \nlocation to connect. This wastes time and resources studying projects that are not real. \nWorse yet, it can inflate expected load growth by modeling projects that do not \nmaterialize, leading to double counting, inaccurate market signals, and unnecessarily high \nprices for consumers. Today, we target speculative projects by establishing escalating \nreadiness requirements for distinct phases of the study process to deter duplicative or \nspeculative requests for transmission service. I strongly encourage RTO/ISOs to pursue \nother improvements to load forecasts, such as using objective screening criteria like \nphysical site control, to ensure that the data used to plan the grid is as accurate as \npossible.5 \n \nFostering Innovation: As I have said, to meet the moment, “a business-as-usual \napproach . . . will not suffice.”6 Building new infrastructure is difficult and costly, which \ndelays efforts to connect large loads to the grid quickly, reliably, and cost effectively. \nThis is doubly true when generation and load are planned and studied separately. \nToday’s orders push beyond this status quo. \n \nFirst, today’s orders promote flexible transmission services—that is, non-firm \nservice to a co-located load that is willing and able to limit withdrawals from the grid—in \nevery RTO/ISO (see Figure 2). As we explained when we first created these \ntransmission services in PJM for co-located loads, customers willing to embrace \nflexibility can reduce the need for Network Upgrades and generating capacity to serve a \nco-located load, which speeds up connecting to the grid and reduces costs for the co-\nlocated load as well as other retail customers. \n \nSecond, today’s orders recognize that extending these same transmission services \nto large loads that are not co-located but that may also be willing to limit their \nwithdrawals from the grid can unlock even more efficiency. Just as for co-located loads, \nlegalizing flexible transmission service options for more large load customers can speed \ninterconnection, avoid constructing unnecessary transmission upgrades, reduce strain on \nthe grid, and make power bills cheaper for everyone. \n \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":98,"startToken":37482,"endToken":37961,"text":"Docket No. EL26-71-000 \n- 5 - \n \nFinally, today’s orders embrace yet another innovation. Load and generation need \nnot be co-located to reduce the number of Network Upgrades; in other words, literal co-\nlocation is not the only way to facilitate faster, more efficient, and more cost-effective \nconnections to the grid. Rather, where a large load and an associated generator are \nelectrically proximate (i.e., close together) and studied together, the reliability impacts on \nthe grid may be more limited than if the load and generator are studied separately. Just \nlike with co-location, more limited impacts on the grid mean, all else equal, fewer \nNetwork Upgrades, which makes connecting to the grid faster, more efficient, and \ncheaper for both the large load and the associated generator. That last point is key. To \nadd new supply to the grid, we must create incentives for “Bring Your Own New \nGeneration.” Today’s orders make BYONG faster and more efficient. \n \nSPP has been a leader in showing how to push beyond the status quo. With its \ninnovative HILLGA proposal, approved by the Commission in January,7 SPP leveraged \nthe opportunity for speed and efficiency by studying load and generation together, and by \ncreating a limited, expedited interconnection service to connect faster. By matching the \ngenerator’s output to the electrically proximate large load’s demand, the impacts to the \ngrid are less than they otherwise would be, minimizing the need for time-consuming and \ncostly Network Upgrades needed to connect. HILLGA is one solution that works for \nSPP, but today’s orders direct other regions to follow SPP’s lead in ways that work for \nthem. Today’s orders add a key tool by ensuring that all RTO/ISOs can study load and \ngeneration together. \n***** \n \nThe Commission’s action today is an important step forward, but the Commission \ncannot accomplish this work alone. States are essential partners in this work. The \nCommission’s actions here respect the long-standing jurisdictional line between federal \nand state authority provided by Congress and repeatedly affirmed by the Supreme Court. \nStates retain exclusive jurisdiction to allocate the costs of FERC-jurisdictional \ntransmission charges among their retail ratepayers, including co-located loads. States \nalso hold the keys to energy infrastructure permits, so we rely on their decisions to ensure \nthat needed transmission and generation get built. At a time when some large loads are \nretail customers that can consume as much energy as a small city, it is imperative that we \nwork within our respective jurisdictions, but that we collaborate. I look forward to \ncontinued collaboration. \n \nToday’s orders begin an important dialogue with RTO/ISOs. As a potential next \nstep, today’s orders invite RTO/ISOs to respond by submitting proposals under FPA \nsection 205. I cannot encourage this enough. I also encourage public utilities outside of \nRTO/ISOs across the country to do the same. The electric industry is rapidly evolving \n \n7 See Sw. Power Pool, Inc., 194 FERC ¶ 61,031 (2026)."},{"page":99,"startToken":37961,"endToken":38081,"text":"Docket No. EL26-71-000 \n- 6 - \nwith regions experiencing and addressing these challenges in different ways. Many of \nthe examples on which the actions in today’s orders are based on stakeholders thinking \ncreatively to develop solutions, and I welcome other new, innovative, and regionally \ntailored proposals that build on the four key pillars set forth today: (1) Protecting \nConsumers, (2) Safeguarding Reliability, (3) Enhancing Transparency, and (4) Fostering \nInnovation. Only by working together can we rise to the occasion and meet this once-in-\na-generation moment to deliver the reliable and affordable energy on which we all \ndepend. It will not be easy, but I remain optimistic and look forward to the path ahead. \nFor these reasons, I respectfully concur. \n \n \n \n________________________ \nDavid Rosner \nCommissioner"},{"page":100,"startToken":38081,"endToken":38083,"text":"Figure 1"},{"page":101,"startToken":38083,"endToken":38085,"text":"Figure 2"},{"page":102,"startToken":38085,"endToken":38305,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nCalifornia Independent System Operator Corporation \nCitizen S-Line Transmission LLC \nCitizens Sunrise Transmission LLC \nCitizens Sycamore-Penasquitos Transmission LLC \nCity of Anaheim, California \nCity of Azusa, California \nCity of Banning, California \nCity of Colton, California \nCity of Pasadena, California \nCity of Riverside, California \nDCR Transmission, L.L.C. \nDesertLink, LLC \nGridLiance West LLC \nHorizon West Transmission, LLC \nLS Power Grid California, LLC \nMorongo Transmission LLC \nPacific Gas and Electric Company \nSan Diego Gas & Electric Company \nSouthern California Edison Company \nStartrans IO, L.L.C. \nSunZia Transmission, LLC \nTrans Bay Cable LLC \nValley Electric Association, Inc. \nViridon Path 15, LLC \nWestern Area Power Administration \nDocket No. EL26-71-000 \n \n \n \n(Issued June 18, 2026) \n \nSEE, Commissioner, concurring: \n \n \nGrowing electricity demand underscores America’s economic strength and the \nopportunities that come with it. And with new opportunities come new challenges. The \npace and scale of emerging large loads create new circumstances that require us to adapt \nin how we build and manage the grid. Large and flexible loads can materially change \nsystem operations, for instance, as well as near-term planning needs, upgrade \nrequirements, and how we allocate costs. Most existing systems were not designed to \naccommodate those changes—especially not at the pace needed to support AI growth and \nadvanced manufacturing that are central to America’s economic competitiveness. As a"},{"page":103,"startToken":38305,"endToken":38771,"text":"Docket No. EL26-71-000 \n- 2 - \n \nresult, uncertainty over the operative rules and delays in interconnecting large loads can \nundermine reliability and investment and add unacceptable and avoidable costs. \n \nToday, the Commission takes strong action within our jurisdictional sweep to \naddress these and other challenges that large load growth poses to the interstate \ntransmission system. Today’s orders support both just and reasonable rates and speed to \n(reliable) power. I’m deeply grateful for the many commenters who shared their insight \nand ideas in this action. They let us build a record that highlights the need for clearer \nprocesses, better information, and faster analysis while our country moves new large load \nadditions online. As we press forward in these dockets, I will be looking to continue \nbuilding on the momentum already underway across the country to craft more practical, \nregion-specific solutions that support timely action while protecting consumers. Our \ncontinued ability to deliver reliable and affordable electricity requires nothing less. \n \nToday’s orders speak for themselves. I write separately to briefly highlight two \nprinciples baked throughout them and that I believe must remain central as the \nCommission evaluates further steps. \n \nFirst, these issues extend beyond the Commission. Creating efficient, predictable \nlarge load interconnection processes is a joint and overlapping task for us, other federal \nagencies, the States, and the RTOs/ISOs and utilities. My animating principle here is that \nwe must use FERC’s statutory authority to bring clarity to the parts of this national issue \nwe own, and to complement and aid others as they tackle theirs. The very procedure the \nCommission deploys today reflects that goal: Recognizing the value in region-specific \napproaches, we are directing individual action in each of the RTO/ISO regions and \nencouraging—strongly—proposals under section 205 of the Federal Power Act from \ntransmission providers or other entities that are molded to their unique system needs. \n \nMost critically, exercising our authority fully without hamstringing our regulatory \nand industry partners means respecting the States. States make many of the key decisions \nthat affect how we manage large loads. States bring indispensable expertise over local \nconditions, siting needs, retail structures, and the resource decisions within their borders. \nAnd they have been hard at work pursuing the retail implications and other State-specific \nconcerns that large load interconnection presents.1 All this effort flows from the States’ \nstatutorily preserved role in regulating the power system. Today’s order understands that \nlimit—our power “extend[s] only to those matters which are not subject to regulation by \nthe States.”2 It also embraces the value in a statutory lens that views large load issues as \nan area of shared federal-State responsibility. As we require clear study and operational \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":104,"startToken":38771,"endToken":39271,"text":"Docket No. EL26-71-000 \n- 3 - \n \nparameters for large load interconnection, we should remember that the nation’s energy \nlandscape is not monolithic. State and regional diversity is a strength, and today’s orders \nknow that the best solutions reflect differing system characteristics. Our action today is \ndesigned to support further State efforts in this urgent and fast-moving space, not \noverride them. \n \nSecond, affordability must be at the forefront as we protect consumers from \nunnecessary costs in a time of rising demand. True, the Commission lacks authority over \nall the factors that drive electricity costs at the retail level. Today’s orders recognize that. \nIn response, the orders strive to aid the States in their front-line affordability duties by \ngetting into their hands all relevant information about Commission-jurisdictional costs. \nAs these matters move forward, I am particularly interested in continued feedback from \nthe States on what information they most need to assess cost implications as new loads \ncome online. Are the cost transparency measures we identify today sufficient, or are \nadditional or more granular data needed for States to appropriately suballocate \ntransmission costs among retail customers? Tools like alternative cost allocation \nstructures, greater clarity in transmission service agreements, accounting for States’ \nlarge-load-specific tariffs, and direct assignment in appropriate cases may help States \nensure that retail consumers do not bear costs incommensurate with the benefits they \nreceive. \n \nMoving to areas where the Commission has a more direct role in ensuring cost \nresponsibility, we need to pull all the levers we have to keep rates fair and transparent. \nToday we reaffirm our responsibility to assign jurisdictional costs to the customers who \ndrive or benefit from grid upgrades, not shift them onto families and small businesses. \nFor instance, today’s orders seek to reduce large-load driven network upgrade costs \nthrough alternative transmission technologies, or ATTs (also commonly called Grid \nEnhancing Technologies). In determining how best to meet the needs of this historic \nlarge load growth, technologies that can improve system capability faster than traditional \nupgrades and at lower costs deserve a hard look. ATTs may not be the best tool in every \ncircumstance, but where they are they can support timely interconnections and avoid \npotentially tens or hundreds of millions of dollars in unnecessary network upgrade costs \nthat would otherwise flow into transmission customers’ bills. \n \nSo our approach today supports continuing the Commission’s policy to roll most \nnetwork upgrade costs—including those in the large load space—into the embedded-cost \nrate most transmission customers pay. But it includes an asterisk that this policy works \nfor ratepayers only so long as we remain committed to pursuing technological \ninnovations that keep those costs at a responsible and accountable level. Today’s order \nthus calls for transmission providers to sufficiently evaluate ATTs to assess if and how \nthey can meet large loads’ interconnection needs. The answer may be yes or no in a \ngiven case. But if the transmission provider opts for traditional network upgrades, they \nmust demonstrate why ATTs are not feasible or would not result in lower costs or a faster"},{"page":105,"startToken":39271,"endToken":39681,"text":"Docket No. EL26-71-000 \n- 4 - \n \ntimeline for the large load interconnection customer. In short, the goal is to respect \ntransmission providers’ engineering judgments while protecting against upgrade costs \nwhen ATTs could solve transmission needs faster and with a lower bill. \n \nI am also sensitive to novel questions about cost shifting that interconnecting large \nload may present. Today’s findings on cost recovery agreements between transmission \nowners and Eligible Customers are an important step in mitigating the risks of stranded \nassets if large loads prove speculative. We are also reducing unnecessary redundancy by \nallowing an Eligible Customer to meet its financial security requirements by relying on \ncredit support or other financial security a large load customer may have posted under a \nretail agreement. As we gain more experience studying transmission service requests on \nbehalf of large loads, it may become appropriate to further streamline financial security \narrangements. Perhaps, for instance, cost -recovery agreements between a transmission \nowner and a large load customer itself could satisfy an Eligible Customer’s financial \nsecurity requirements. As we move forward, I’ll be looking to ensure cost-recovery \nagreements contain fair and transparent measures to ensure the right costs get on the right \nbills. (Relatedly, the discussion about the full nature of transmission-related charges in \nour concurrent PJM Order on Rehearing, Clarification, Compliance, and Paper Hearing3 \nmay prove relevant here: Real-world experience with new transmission services for co-\nlocated load may clarify if future action becomes needed to address potential cost shifts \nas Eligible Customers take new transmission services on behalf of large loads.4) \n \nMore generally, as we gain more experience as an industry and a country in \ngetting large loads connected to the grid, I welcome bold proposals to keep affordability \ncentral. Large load growth presents a real opportunity to build a stronger, more capable, \nand more reliable electric system that can benefit all ratepayers. Meeting that opportunity \nat the pace we need and at an acceptable cost requires innovative thinking and fast action. \nI commend the States in their continued work in these areas. I urge the RTOs and ISOs \nto continue their good work as they respond quickly to today’s orders. I also remain \ncommitted to moving forward within the Commission’s statutory zone with clarity and \ndecisiveness. I am proud to support the Commission’s important steps today. And we all \nhave more work ahead. \nFor these reasons, I respectfully concur. \n \n \n \n3 PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026). \n4 See id. P 456."},{"page":106,"startToken":39681,"endToken":39689,"text":"Docket No. EL26-71-000 \n- 5 - \n \n \n______________________________ \nLindsay S. See \nCommissioner"},{"page":107,"startToken":39689,"endToken":39893,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \n \nCalifornia Independent System Operator Corporation \nCitizen S-Line Transmission LLC \nCitizens Sunrise Transmission LLC \nCitizens Sycamore-Penasquitos Transmission LLC \nCity of Anaheim, California \nCity of Azusa, California \nCity of Banning, California \nCity of Colton, California \nCity of Pasadena, California \nCity of Riverside, California \nDCR Transmission, L.L.C. \nDesertLink, LLC \nGridLiance West LLC \nHorizon West Transmission, LLC \nLS Power Grid California, LLC \nMorongo Transmission LLC \nPacific Gas and Electric Company \nSan Diego Gas & Electric Company \nSouthern California Edison Company \nStartrans IO, L.L.C. \nSunZia Transmission, LLC \nTrans Bay Cable LLC \nValley Electric Association, Inc. \nViridon Path 15, LLC \nWestern Area Power Administration \nDocket No. EL26-71-000 \n \n \n \n(Issued June 18, 2026) \n \nCHANG, Commissioner, concurring: \n \n \nIn a series of orders today, the Commission initiates separate proceedings under \nFederal Power Act (FPA) section 206 to explore the impact of the increasing growth of \nlarge loads in Regional Transmission Organization (RTO) and Independent System \nOperator (ISO) regions. The preliminary findings in these orders, and the associated \nproposed reforms to RTO/ISO and transmission owner tariffs, could significantly change \nhow loads procure, use, and pay for transmission service, with ramifications for \nRTO/ISO operations, planning, and markets. I write separately to emphasize the"},{"page":108,"startToken":39893,"endToken":40322,"text":"Docket No. EL26-71-000 \n- 2 - \n \nimportance of building actionable records in these proceedings, particularly with respect \nto our consideration of customer protection, transmission service, and alternative \ntransmission technology reforms. \nI. \nOverview of Today’s Orders \n \nIn each of today’s orders to show cause, the Commission identifies a series of \nissues raised by the ongoing growth of large loads, directs briefing on whether existing \ntariffs remain just and reasonable in light of those developments, and describes possible \nsolutions to those issues if the Commission ultimately concludes that the relevant tariffs \nare unjust and unreasonable. Each order is directed to a specific RTO/ISO and relevant \ntransmission owners that play a role in interconnecting large loads to the Commission-\njurisdictional transmission system. The Commission does not pursue the broad assertion \nof jurisdictional authority contemplated in the Advanced Notice of Proposed \nRulemaking, which I hope assuages concerns raised by our state colleagues that the \nCommission ought not encroach upon matters properly left to their jurisdiction.1 \n \nBroadly summarized, each order seeks regional input on a specific list of issues: \n(1) the clarity and consistency of existing rules governing how each RTO/ISO and its \nrelevant transmission owners analyze the impact of providing transmission service to \nEligible Customers on behalf of large loads; (2) whether each RTO/ISO tariff requires \nreforms to mitigate the risk of cost shifting among wholesale transmission customers; (3) \nwhether each RTO/ISO tariff (other than PJM) requires additional clarity regarding the \nprovisions addressing co-located generation and load arrangements; (4) the potential \nextension of new firm and non-firm transmission services to co-located load, load with \nbehind the meter generation, and other flexible loads; and (5) the need for reforms, \nmodeled on Southwest Power Pool, Inc.’s High Impact Large Load Generation \nAssessment concept, to facilitate a process through which a generator may temporarily \nserve a co-located or electrically proximate load until interconnection and transmission \nservice is available. The Commission also invites each region to submit FPA section 205 \nfilings that can address each issue identified in the orders, thereby resolving the \nCommission’s concerns. \nII. \nThe Commission Needs Good Records to Ensure Reasoned Decision-Making \n \nI first want to emphasize that the Commission needs active participation from \ninterested stakeholders to develop thorough records in each region. The Commission \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":109,"startToken":40322,"endToken":40784,"text":"Docket No. EL26-71-000 \n- 3 - \n \ncannot make reasoned decisions about whether reforms might be needed without an \naccurate understanding of the existing processes, which differ by region. Because the \nCommission is acting via FPA section 206 rather than generically through a rulemaking, \nthe issues addressed by these orders will be subject to ex parte restrictions across the \nRTOs/ISO regions, including with our state colleagues whose regulation can and will \ndirectly affect the individual transmission owners that need to comply with the orders \nissued today. This will limit the Commission’s ability to engage in informal fact-finding \nand discussions with regional stakeholders, and thus, it is even more essential that the \nrecord in each region fully reflects the views of all interested parties. \n \nSecond, I highlight three issues below that will be especially important to the \nsuccess of this effort, and I hope that interested parties will take particular care in helping \nthe Commission address those issues. Importantly, I recognize that the record established \nin each RTO/ISO region will (and should) differ, which will allow the Commission to \nensure any required changes to an RTO/ISO’s tariff are appropriately tailored to that \nregion’s needs. \nIII. \nThe Commission Needs to Pursue Meaningful Customer Protection \n \nThe FPA is fundamentally a customer protection statute,2 and the Commission has \nan obligation to ensure that the rates that wholesale and transmission customers pay are \njust and reasonable. Rapid large load growth has strained planning and resource \nprocurement processes around the country, as transmission owners, load serving entities, \nand generators accelerate the building of new infrastructure needed to serve these new \nloads. As we develop the new infrastructure, many have raised concerns about whether \nthese costs are being fairly assigned to new and existing customers, whose benefits must \nbe commensurate with the costs they pay. While individual states have been exploring or \nusing various approaches to protect retail customers against unjustified cost shifts, the \nCommission to date has not initiated any proactive exploration of how to protect \nwholesale customers against unjustified cost shifts. I am laser-focused on this issue \nbecause we should not create unjustified costs for consumers in our efforts to connect and \nserve large loads. \n \nIn today’s orders, the Commission launches an inquiry into whether existing \nRTO/ISO tariffs include adequate mechanisms to mitigate the risk of undue cost shifting \namong transmission customers. To address this risk, the Commission preliminarily \nidentifies a two-part solution: (1) that each RTO/ISO post public information about the \namount of new large loads seeking to connect to the RTO’s/ISO’s transmission system, \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":110,"startToken":40784,"endToken":41210,"text":"Docket No. EL26-71-000 \n- 4 - \n \nany Network Upgrades identified in the local transmission planning process to serve \nthose loads, and the costs of those Network Upgrades; and (2) that each RTO/ISO adopt a \npro forma cost recovery agreement to help ensure that Eligible Customers serving large \nloads bear the risk and are ultimately responsible for costs incurred to provide \ntransmission service. I strongly support this effort to provide additional transparency \nregarding jurisdictional transmission service requests and the costs associated with \nproviding transmission service to the requesting parties, as the Commission cannot \neffectively execute its statutory responsibilities without sufficient understanding of the \ncosts that feed into jurisdictional rates. \n \nExploring how agreements between transmission owners and Eligible Customers \ncan protect wholesale customers against cost shifts is important. However, as I have \npreviously explained, bilateral agreements that simply provide transmission revenue \ncontributions untethered from any assessment of the actual cost of providing transmission \nservice induced by individual large loads may be insufficient to adequately protect other \ncustomers against unjustified cost shifts.3 It is therefore important that the resulting \nregulatory and rate design are not limited to a pre-defined solution set, and that parties \nprovide the Commission with comprehensive records outlining various and innovative \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 \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"},{"page":111,"startToken":41210,"endToken":41624,"text":"Docket No. EL26-71-000 \n- 5 - \n \nproposed solution, the Commission needs a robust record in each docket and each region \nto ensure we establish the right cost shift protections for wholesale customers, including \nbut not limited to the commitments outlined in the Ratepayer Protection Pledge.7 \n \nI support initiating our own review of customer protection approaches, rather than \nsimply relying on voluntary commitments that may fall short of optimal protection, \nbecause the Commission has the opportunity and obligation to get this issue right. I \ntherefore encourage interested parties to assist the Commission in that effort by clearly \nand comprehensively explaining the benefits and tradeoffs of alternative customer \nprotection approaches. How power infrastructure costs will be assigned across Eligible \nCustomers that serve large loads and other customers is at the core of the efforts we \ninitiate today. \nIV. \nThe Commission Needs to Understand the Implications of Extending New \nTransmission Services to Additional Loads and Regions \n \nThe orders also preliminarily find that the Commission should extend the \ntransmission services developed in the PJM co-location proceeding – Interim NITS, Firm \nContract Demand, and Non-Firm Contract Demand – to new types of load and new \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.8 \nWhile these services have the potential to facilitate more efficient use and build out of the \ntransmission system, they also contemplate running the system “tighter” than we have \ndone in the past, potentially with more loads on the system served by co-located or \nbehind-the-meter generation, and potentially more use of batteries, load control systems, \nand backup resources to manage demand during system peaks or other stressed \nconditions. While it is important to identify innovative solutions that can adapt to the \nneeds of the system, the Commission and grid operators must also be careful not to \nimplement changes that create unforeseen reliability risks. Ultimately, we must find the \nproper balance (and I would argue we are exploring a new balance) between costs of \ninvestments versus reliability. \n \nThe Commission’s experience in the PJM co-location proceeding highlights the \ncomplexities and challenges of introducing these new transmission services, which have \nsignificant ramifications for system operations, transmission planning, grid reliability, \n \nhttps://gridstrategiesllc.com/project/federal-transmission-pricing. \n7 Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 2026). \n8 This is particularly true in CAISO, which does not rely upon the Order No. 888 \nNITS framework."},{"page":112,"startToken":41624,"endToken":42061,"text":"Docket No. EL26-71-000 \n- 6 - \n \nmarket dispatch, resource adequacy, and cost allocation. As the Commission considers \nwhether to expand these transmission services to new types of load and new regions, I \nencourage commenters to address what impacts the introduction of new firm and non-\nfirm transmission products would have in their regions, as well as any relevant \ncharacteristics that might distinguish their regions from the Commission’s findings in the \nPJM co-location docket. Ultimately, this topic will have direct long-term impacts on how \nfuture transmission systems will be planned and configured, how efficiently future power \nmarkets will operate, and how customers will respond to prices and system needs. \nTherefore, I am specifically interested in understanding how extending the new \ntransmission services might affect individual suppliers or customers, as well as how \nexisting systems or processes might be affected by these new services. I am open to \nunderstanding how these services might be helpful to a region or that they may create \nproblems not yet anticipated. \nV. \nThe Orders Recognize the Importance of Evaluating Advanced Transmission \nTechnologies \n \nLastly, today we preliminarily find that each RTO/ISO’s tariff is unjust and \nunreasonable because the tariff lacks clear and consistent provisions requiring the \nevaluation of alternative transmission technologies as potential solutions to accommodate \nan Eligible Customer’s request for transmission service on behalf of a large load. \nSpecifically, it is important for RTO/ISOs and transmission owners to evaluate whether \nalternative transmission technologies are feasible in reducing the cost of transmission \nsystem upgrades or allow for a faster timeline for accommodating the transmission \nservice request. As many transmission owners have explored various alternative \ntechnologies in pilot projects,9 it is time to roll out all available technologies to reduce \n \n9 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-"},{"page":113,"startToken":42061,"endToken":42268,"text":"Docket No. EL26-71-000 \n- 7 - \n \nrisks and costs for customers, as well as help the industry continue to develop new \ntechnologies that can increase the robustness of our transmission system while protecting \ncustomers from higher costs. \nVI. \nConclusion \n \nToday’s orders address some of the most consequential issues currently in the \nindustry and before the Commission. I hope that these proceedings provide vehicles \nthrough which the Commission can provide much-needed clarity and direction, and it is \nimperative that we build strong and comprehensive records on each issue in each region \nto inform our decision-making. I therefore encourage all interested parties to fully \nengage and help the Commission navigate these complex, multi-faceted challenges. Our \nsuccess will ultimately be measured by our shared ability to deliver reliable and \naffordable power to all customers, to ensure new loads can interconnect in a timely \nfashion while paying their fair share of system costs, and to protect existing customers \nagainst adverse reliability or economic impacts. \nFor these reasons, I respectfully concur. \n \n \n________________________ \nJudy W. Chang \nCommissioner \n \n \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":114,"startToken":42268,"endToken":42508,"text":"UNITED STATES OF AMERICA \nFEDERAL ENERGY REGULATORY COMMISSION \n \nCalifornia Independent System Operator Corporation \nCitizen S-Line Transmission LLC \nCitizens Sunrise Transmission LLC \nCitizens Sycamore-Penasquitos Transmission LLC \nCity of Anaheim, California \nCity of Azusa, California \nCity of Banning, California \nCity of Colton, California \nCity of Pasadena, California \nCity of Riverside, California \nDCR Transmission, L.L.C. \nDesertLink, LLC \nGridLiance West LLC \nHorizon West Transmission, LLC \nLS Power Grid California, LLC \nMorongo Transmission LLC \nPacific Gas and Electric Company \nSan Diego Gas & Electric Company \nSouthern California Edison Company \nStartrans IO, L.L.C. \nSunZia Transmission, LLC \nTrans Bay Cable LLC \nValley Electric Association, Inc. \nViridon Path 15, LLC \nWestern Area Power Administration \nDocket No. EL26-71-000 \n \n(Issued June 18, 2026) \n \nLACERTE, Commissioner, concurring: \n \n \nI support today’s fleet of show cause orders. We are at an inflection point in the \nhistory of American energy infrastructure. The extraordinary and rapid growth of large \nloads in RTOs and ISOs is faster than the current system can handle. This order charts a \ncourse for addressing the potential gaps and shortcomings in CAISO’s Tariff and/or the \nTransmission Owner Tariffs (TO Tariffs) that need to be resolved to appropriately \nrespond to this growth, as informed by careful review of the thousands of pages of \ncomments received in response to the advance notice of proposed rulemaking (ANOPR).1 \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);"},{"page":115,"startToken":42508,"endToken":42979,"text":"Docket No. EL26-71-000 \n- 2 - \n \nI write separately to underscore my expectation for RTOs and ISOs, including CAISO \nand/or the Participating Transmission Owners, to timely submit their robust, thoughtful, \nand region-specific proposals to address the concerns that we have preliminarily \nidentified in their respective tariffs and agreements. By harnessing your region-specific \nexpertise and creativity to bring tailored solutions to the table, together we can \nefficiently, reliably, and affordably integrate large load, co-located load and generation \nand/or storage, as well as electrically proximate large load onto the transmission system. \nI also support the use of alternative transmission technologies to unlock every megawatt \nof existing capacity from our current transmission system. We have the technology. We \nshould use it now to enable faster interconnection of large loads, lower costs to \ncustomers, and help prevent cost shifting. \n \nTo that end, and in light of our action in today’s orders, I also ask the state public \nutility commissions—whether they have already approved large load retail tariffs, are in \nthe process of crafting large load retail tariffs, or have yet to embark on this essential \ntariff design process—to take a hard look and ensure their large load retail tariff \nprovisions insulate ratepayers from the negative impacts of data center growth. \nAdditionally, I expect CAISO and/or the Participating Transmission Owners to design \nproposals in response to this show cause order that dovetail with the efforts on the retail \nside to implement the Ratepayer Protection Pledge, protect customers, and ensure that \nlarge loads cover the costs they incur to integrate with the grid. \n \nThe stakes here could not be higher and every gambler knows that the secret to \nsurviving is knowing what to throw away and knowing what to keep.2 Today’s orders do \nexactly that—adopting thoughtful proposals that position our nation for success, driving \nmeaningful change, and rejecting the gridlock, half-measures, and failure to plan that \nhave gone on for far too long. The data center odyssey that we embarked upon first with \nPJM, then SPP, we now aggressively extend to all the RTO/ISO regions.3 Enabling the \nswift and efficient interconnection of large loads to the transmission system while \nmaintaining affordability, reliability, commitment to open access, competitive principles \nand cooperative federalism, will only be achieved through consistent, coordinated action \n \nsee also Letter from Chris Wright, Sec’y, U.S. Dep’t of Energy (Oct. 23, 2025) \n(Secretary’s Letter). \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))."},{"page":116,"startToken":42979,"endToken":43483,"text":"Docket No. EL26-71-000 \n- 3 - \n \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 CAISO’s and/or the TO Tariff(s), may be unjust and unreasonable and/or \nunduly discriminatory or preferential because they lack features necessary to timely, \nreliably, and safely interconnect and serve new large loads in a way that produces just \nand reasonable rates. \n \nI commend each commentor for their robust and ongoing responses to the \nconcerns that Secretary Wright and the Commission raised in the ANOPR proceeding. \nThe comments helped us identify the common issues, common solutions, and individual \ndifferences among the RTOs/ISOs. We heard a plea for broad flexibility and regionally \ntailored solutions. And we will strive to work towards those solutions, not through top-\ndown, one-size-fits-all mandates, but through consideration of region-specific proposals. \nAnd we endeavor to support an appeal for federal policies that build upon rather than \ndisrupt current and planned developments, reflecting state and local processes and \nstakeholder efforts. Through these individually tailored and region-specific show cause \norders, we are delivering to ensure that our transmission system can accommodate new \nlarge loads in a timely, safe, and reliable manner. And, importantly, in a manner that \nensures benefits and protection for all customers. Affordability remains a top concern as \nwe proceed forward. \n \nThe collective voices in the ANOPR comments have shaped our decision to issue \nsix separate individually tailored and region-specific show cause orders, rather than a \nproposed final rule at this time. But the success of the next phase of this journey rests \nwith you, CAISO, and/or your Participating Transmission Owners, and your \nstakeholders. We are directing you to expeditiously bring forward for our consideration \nyour novel, region-specific solution(s). Time is of the essence. By inviting you to \nproceed under FPA section 205, we are giving you significant perks: the benefits of first \nwielder of the pen and the relatively capacious standard under FPA section 205 that \nallows us to accept a potentially broad range of proposals provided they are shown to be \njust and reasonable and not unduly discriminatory or preferential.5 We are even giving \n \n4 Admittedly, we are further down the road in some regions as compared with \nothers. \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)"},{"page":117,"startToken":43483,"endToken":43952,"text":"Docket No. EL26-71-000 \n- 4 - \n \nyou flexibility to propose the implementation date for your innovative proposals. But \nsuch freedom comes with great and concomitant responsibility. \n \nThis is not a time to be cavalier and dodge the urgent need to meet the moment. \nWhile this is a long journey, even so, we must continue to move at breakneck pace to win \nthe AI race. So let me be direct. If you choose not to submit timely, reasonable, non-\ndiscriminatory or preferential, comprehensive, and substantiated proposal(s), as directed \nand as required under our applicable statutes, your deficient response will not go \nunnoticed. I am prepared to play jurisdictional hardball, if needed.6 This Commission \nhas appropriately exercised considerable restraint in asserting the full scope of our \njurisdiction in these orders. However, the Commission has very broad jurisdiction over \ntransmission that we will not hesitate to utilize as necessary to ensure that we meet our \nobjectives in all show cause proceedings, including this CAISO and/or the Participating \nTransmission Owners proceeding we initiate here. If we find your Tariff is in fact unjust \nand unreasonable and unduly discriminatory or preferential, any failure on your end to \nprovide a sufficient FPA filing or filings to address the large-load-related concerns that \nwe have identified will result in the Commission dictating the solutions for you. I say \nthis not as a threat, but as a statement of duty. While you may not like our remedies—I \nhave often said that the federal government generally does not come up with the best \nsolutions—this is an outcome we are prepared to pursue given the gravity of the moment \nand our statutory obligation. Notwithstanding our readiness to step in, it greatly benefits \neveryone for you to come up with an approach tailored to your region. \n \nI will end my concurrence where I began: We have heard your concerns, and, let \nme underscore, now is the time for you to heed ours. This is an extraordinarily \nconsequential proceeding. The stakes for reliability, for affordability, and for the \nAmerican ratepayer could not be higher. We owe it to the public to get this right. I look \nforward to reviewing and acting as expeditiously as possible on your responses to this \nshow cause order, which I expect will include an FPA section 205 proposal or proposals. \n \nFor these reasons, I respectfully concur. \n \n(comparing the respective authorities of the Commission and public utilities under \nsections 205 and 206). \n \n6 16 U.S.C. § 824(b); New York v. FERC, 535 U.S. 17 (2002) (“There is no \nlanguage in the statute limiting FERC’s transmission jurisdiction to the wholesale \nmarket[.]”)) (emphasis in original); id. at 20 (stating that “the FPA authorizes FERC's \njurisdiction over interstate transmissions, without regard to whether the transmissions are \nsold to a reseller or directly to a consumer[.]”)."},{"page":118,"startToken":43952,"endToken":43959,"text":"Docket No. EL26-71-000 \n- 5 - \n \n \n \n______________________________ \nDavid LaCerte \nCommissioner"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":2565,"startToken":0,"endToken":286},{"p":2,"at":2565,"title":"D. Extending New Transmission Services to Eligible Customers Taking Service on","method":"printed heading","endPage":2,"endAt":2764,"startToken":286,"endToken":303},{"p":2,"at":2764,"title":"E. 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